Description
It describes on financing project.It takes the case of TATA Mundra power project.
TATA MUNDRA POWER PROJECT
Index
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Topic Page No. Introduction Sponsor Analysis Tata Group Tata Power Project Details Environmental and Social Concerns Assessment Power Plant Operations & Implementations Agreements Power off take agreements Indian Economy-Outlook Power Sector –Overview Electricity Act 2003 UMP CDM Kyoto Protocol CERC Risks Conclusion Financials References 3 4 4 4 8 11 12 15 20 20 30 31 34 35 36 38 42 43 51
INTRODUCTION
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The Mundra Ultra Mega Power Project is developed by Coastal Gujarat Power Limited (CGPL) in response to the plan of the Government of India to increase the electricity production capacity of the country by 100,000 megawatts by the year 2012. To achieve economies of scale, the Government prefers large-scale projects that can meet the requirements of a number of states. The Project, awarded to CGPL on a build, own, and operate basis, is a supercritical coal-fired power plant with a total capacity of 4,000 MW. Various packages are currently at the bidding stage, and the Project is scheduled for full commercial operation in June 2012. The Project is located in a coastal area of Mundra Taluka, in Kutch District of Gujarat State. The project area covers 1,254 hectares of vacant land near the villages of Tunda and Wandh, including 202 ha of right of way outside the project boundary, and is about 2 km from the first-phase development area of the Mundra Special Economic Zone (MSEZ), where a 660 MW power plant project, the Adani Power Project, is being implemented by Adani Power Limited. The project area is about 1.5 kms from the sea, with a portion of the MSEZ intervening between the sea and the project area. For logistics and accessibility, the Project relies on (i) Mundra Port (about 25 km from the project site); (ii) state highway SH-6 (about 6 km) connecting Mundra and Mandvi; (iii) national highway extension NH 8A (about 15 km), connecting Gandhidham and Anjar with Mandvi; (iv) Adipur railway station (85 km); and (v) Bhuj airport (75 km). An access road will be constructed to provide direct access to the project site from state highway SH-6, bypassing the two villages. As many as 13 bidders submitted their bids at RFQ stage. Of these, 2 were rejected at RFQ stage itself. Of the remaining 11, 6 submitted the financial bids. The bids were as follows:
Tata Power Company Limited quoted the lowest levelised tariff for 25 year period and was awarded the project. Subsequent to completion of other formalities, TPC paid PFC 27.94 crores to acquire 100% shares of CGPL.
SPONSOR ANALYSIS
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TATA Group:
Tata Group is a multinational conglomerate based in Mumbai, India. Tata Group is the largest private corporate group in India in terms of market capitalization and revenues, and has been recognized as one of the most respected companies in the world. It has interests in steel, automobiles, information technology, communication, power, tea and hospitality. The Tata Group has operations in more than 85 countries across six continents and its companies export products and services to 80 nations. The Tata Group comprises 114 companies and subsidiaries in seven business sectors, 27 of which are publicly listed. 65.8% of the ownership of Tata Group is held in charitable trusts. Companies which form a major part of the group include Tata Steel, Corus Steel, Tata Motors, Tata Consultancy Services, Tata Technologies, Tata Tea, Titan Industries, Tata Power, Tata Communications, Tata Teleservices, Tata Auto Comp Systems Limited and the Taj Hotels. Tata group acquired Corus for $12 billion in 2007 which is the largest overseas acquisition by an Indian firm till date.
Tata Power:
Tata Power Company Limited is a Tata Group Company and it is India’s largest private sector power company. The installed capacity of the company currently stood at 2971MW with thermal capacity at 2329MW, hydro at 447MW and wind at 195MW. TPCL has presence in all the segments of power sector such as generation, transmission, distribution and power trading. The company caters to the customers of Mumbai for more than ninety years. Apart from Mumbai and Delhi, the company has generation capacities in Jojobera, Jharkhand and Karnataka. TPCL has carried out several overseas projects and successfully completed erection, testing and commissioning of major power projects in Saudi Arabia, Bangladesh, Kuwait, Algeria, Myanmar and Thailand. The company has also undertaken projects pertaining to power plant / operations management and plant operations training. The company has a Strategic Electronic Division (SED) that has been pursuing development and production activities for the Indian defense sector. SED successfully developed the Multi Barrel Rocket Launcher, ‘Pinaka’, proven in the field through extended user trials which led to its induction into the Indian Army. The Division has developed specialized equipment for Air Defense and Naval Combat systems.
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The company has seven subsidiaries. They are: 1. Costal Gujarat Power Limited 2. Trust Energy Resource Ltd. 3. Maithon Power Ltd. 4. Industrial Energy Ltd. 5. North Delhi Power Ltd. 6. Powerlinks Transmission Ltd. 7. Tata Power Trading Co. Ltd. In June 2007, TPC acquired a 30% stake in the KPC and Arutmin mines of Bumi Resources and is thus focusing on backward integration and fuel security.
Recent Developments: a) Fund Raising Plans TPCL has launched the $250-million FCCB issue, which includes a greenshoe option to raise another $50 million. The bonds will mature in five years and will have a yield-to maturity of 3.5 per cent on a semiannual basis. The money raised through this option will be used to fund the power projects. The company requires a debt of about Rs 236,000mn by March 2012 to complete its ongoing expansion plans. The company has already tied up for debts and other loans from various financial institutions for about Rs.181, 000 mn. TPCL has plans are to raise Rs 28,000mn through internal accruals and the rest through dilution of equity of subsidiaries, disinvestment of various holdings or assets and dilution at parent level through various vehicles. b) Strengthening of Customer Base The company is planning to add 30,000 more customers by March 2010 in Mumbai License Area. TPCL has so far received and processed 3,000 to 4,000 applications for a change-over to TPC's distribution network from mainly residential consumers in Mumbai's suburbs. The company’s current load across Mumbai stood at 400MW, which peaks at 477MW during summer seasons. Currently the company supplies to around 28,000 customers in the license area. c) Tie-Up with Invensys Operation Management
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One of the wholly owned subsidiary of the company, Costal Gujarat Power Limted-which owns Mundra UMPP, has entered into an agreement with Invensys Operations Management, a Texas based company, to optimize India's first ultra-mega 4000MW power plant located in Mundra. Invensys will provide distributed and critical control systems, emergency shutdown systems, advanced process control, plant optimization and operator training simulator technology. Coastal Gujarat Power can leverage the global expertise and engineering capabilities of Invensys, giving them the assurance of proven delivery capability and commitment to train Coastal Gujarat's operators d) Partnership with Norway Firms Norway’s one of the fastest growing international renewable energy company, has signed a partnership agreement to develop hydro power projects in India and Nepal. The partners aim to have 2000 MW under construction or in operation by 2015, and a total of 4000 MW by 2020. This is the first time that TPCL has entered into partnership with another hydropower company. Both the companies have already began pursuing potential project opportunities based on the vast reserves of renewable energy in the Himalayas. e) Coal Block Acquisition TPCL is looking for opportunities to acquire coal blocks in Australia and Mozambique. It is also looking small coal mines in Indonesia. f) Commissioning of Mundra UMPP Units The company is planning to commission two units of the upcoming Mundra UMPP by February 2012. The aggregate capacity of these two units stood at 1,600MW.Among these the first units will commission by September 2011. The project will be commissioned fully by December 2013.
Projects under implementation: Mundra UMPP This 4,000MW project is expected to commission completely by December 2013. Around 31% of the work has been completed. 6
Maithon The first unit of this 1050MW power project is expected to commission by 2010 and the second one by 2011. It is a 74:26 joint venture between TPCL and Damodar Valley Corporation. Jojobera Unit 5 The capacity of this unit is 120MW and is expected to complete by the end the current calendar year. Around 75% of the construction work has been completed. This project is owned by one the company’s subsidiary, IEL. Captive Coal Blocks Mandakini Coal Block This 7.5MTPA coal block is situated in Orissa. Coal production from this is expected to start by July 2011. The company has mining plan approval from MoC and environment clearance, forest land approval & land acquisition are under process. Tubed Coal Block This is a joint venture between the company and Hindalco. This coal block is situated in Jharkhand. Out of the total mining capacity of 5.75MTPA, TPCL is entitled to get 2.30MTPA. Coal production from this is expected to start by February 2012. Tata Power has recently acquired 30% stake in coal fields in Indonesia (which also has ownership of Indonesian ministers)
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PROJECT DESCRIPTION
Project Facilities The project facilities to be constructed by CGPL include the power plant and support facilities within the complex. CGPL will also construct a housing complex for project staff. Associated facilities to be constructed by other entities include: (i) (ii) (iii) (iv) A dedicated jetty and facilities for unloading and handling coal at Mundra Port A merry-go-round (MGR) rail system for transporting coal from the port to the power plant Transmission lines to convey electricity from the power plant to various designated load centers An access road.
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Facilities to be constructed by CGPL Power Plant The power plant will consist of five pulverized coal-fired, supercritical steam electricity-generating stations, each with capacity of 830 MW. In addition to coal, fuel oil will be used for start-up, for flame stabilization, and during low-load operations. The main plant is arranged within the three interconnected structures, the (i) boiler structures, (ii) turbine building, and (iii) integrated control and electrical building. Water Production System The Project will require 25,710 m3/day of freshwater, consisting of 25,280 m3/day for process-uses, including water for coal and ash handling, and 430 m3/day for domestic uses. The freshwater will be produced from seawater in a de-salination plant. For boiler feed, a demineralization plant will further treat the freshwater supplied from the desalination plant.
Cooling Water System The power plant will have a once-through cooling system using seawater. The seawater requirement will be about 15.12 million cubic meters per day (m3/day) of which about 14.99 million m3/day will be for condenser cooling and 0.1278 million m3/day will be for producing freshwater. The seawater will be pumped at the end of an inlet channel connecting to Kotdi Creek. The spent cooling water, warmed to about 7 degrees Celsius (°C) above ambient sea water temperature, will be discharged back into the sea through a discharge channel opening to Mudhwa Creek. The inlet channel will be about 80 meters (m) wide at the bottom, 130 m wide at the top, 3 m deep, and 6.5 km long. Kotdi Creek, about 3.5 km long, will be dredged and trained to enhance its hydraulic capacity. The inlet system (inlet channel and Kotdi Creek) is designed to convey up to 630,000 cubic meters per hour (m3/hr), or somewhat more than the seawater requirement of 550,000 m3/ hr, to meet peak cooling water demand as well as the volume required for freshwater production. The outlet discharge channel will have a base width of 60 m and a length of 4.9 km. It will be designed to cool water over the first 1,900 m from the power plant. The outlet channel will discharge into Mudhwa Creek, which is about 3 km long and will be dredged and trained to increase its hydraulic capacity. Site Drainage Rainwater runoff will be collected in a pond to use in spraying the coal stockyard and for landscaping.
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Wastewater Treatment System All process wastewaters will be treated to remove oil and stored in a pond for use in suppressing coal and ash dust and for landscaping. Reject from the desalination plant will be discharged into the sea through the discharge channel of the cooling water system. A sewage treatment plant will be provided to treat sewage from the housing complex. Residential Complex The operation of the power plant and support facilities will require about 718 people consisting of 255 CGPL staff and 463 outsourced staff. A housing complex consisting of 400 units will be developed on 182 ha of land to provide accommodation for about 255 CGPL staff and a few of the outsourced staff. Access Road An access road will be constructed from state highway SH-6 to the project site to bypass Wandh and Tunda villages.
Associated Facilities to Be Constructed by Other Entities Transmission Lines The net power produced by the power plant will be fed to a 400 kilovolt (kV) switchyard. Three 400 kV double-circuit lines will be constructed to transmit electricity from the power plant’s switchyard to Limbdi (300 km), Ranchodpur (390 km), and Jetpur (330 km). The Power Grid Corporation of India Limited will be responsible for acquiring ownership rights, rights of way, easements, and continued access rights necessary for the construction, operation, maintenance, and upgrading of the new transmission facilities. Coal Shipment and Unloading Facilities The power plant will require 11–13 million metric tons per annum (MTPA) of coal will be imported from sources such as Australia, Indonesia, and South Africa. Existing facilities at Mundra Port can handle only about 4 million MTPA of coal. Therefore, Mundra Port and Special Economic Zone Limited, the port owner, will construct a new berth and install mechanized coal-unloading facilities and a mechanized coalstacking and reclaiming system specifically to meet the coal import requirements of the Project and the Adani Power Project.
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Rail System for Coal Transport Coal will be transported from Mundra Port to the power plant by a MGR rail system with bottom-open, bottom-release wagons. The active coal stock and the reserve stockpile at the power plant site will each be approximately 500,000 metric tons, providing a total of approximately 15 days’ coal supply in addition to the storage capacity of about 500,000 metric tons at the port.
Environmental and Social Impacts Assessment
The assessment of environmental and social impacts of the Project was conducted through the following six separate but related studies: (i) A rapid environmental impact assessment conducted by TCE Consulting Engineers Limited of India from March to May 2006, (ii) A comprehensive environmental impact assessment also conducted by TCE from March 2006 to August 2007 (iii) A socioeconomic assessment report also conducted by TCE from March to August 2006, (iv) A rapid marine impact assessment conducted by the National Institute of Oceanography from January 2006 to April 2007 and supplementary information provided in October 2007 (v) A supplementary investigation of the cumulative impacts on ambient air quality of the Project and the neighboring 660 MW power plant prepared by the Tata Power Company Limited from late October to early November 2007 in consultation with Vishudda Envirotech of India. (vi) A rapid social impact assessment conducted by Saline Area Vitalization Enterprise Limited of India in October 2007. In the course of the environmental and social assessment, a public hearing was held on 19 September 2006, and further consultations were subsequently conducted in villages. The Project received environmental clearance from the Ministry of Environment and Forests (MOEF) on 25 April 2007 based on the rapid environmental impact assessment. All other clearances and permits required for various operations from the national and state authorities have also been obtained.
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Power Plant Operations & Implementations Agreements
Construction CGPL will construct the Project through various packages. A boiler package and a turbine generator package represent approximately 50% of the total project cost. The boiler package will be procured from Doosan Heavy Industries & Construction Company Limited (Doosan) of the Republic of Korea, and the turbine generator package from Toshiba Corporation (Toshiba) of Japan. Doosan Projects Limited, an Indian incorporated company wholly owned by Doosan, is expected to provide onshore supplies and services. TCE Consulting Engineers Limited (TCE) from India will assist in preparing detailed specifications and provide engineering and design support. Korea Power Engineering Company, Inc., a subsidiary of Korea Electric Power Company Limited, the largest power utility in the Republic of Korea, will review and reinforce TCE’s work. Doosan, established in 1962, has become one of the world's major engineering, procurement, and construction contractors; and is one of the few companies in the world with the capability to design and manufacture supercritical boilers. Doosan’s business structure is organized by business groups for power generation, desalination plants, nuclear power plants, casting and forging, and construction. Its power generation business group is active in fields related to fossil fuel power generation, which includes boilers, heat recovery steam generators, turbine and generator equipment, and industrial support facilities such as material handling equipment and environmental systems. Doosan has built more than 300 nuclear, thermal, combined cycle, and hydropower plants. It is currently building more than 60 power plants in the People’s Republic of China (PRC), India, Republic of Korea, United States, and others. Doosan recently provided 660 MW supercritical boilers to National Thermal Power Corporation of India, and manufactured 800 MW supercritical boilers for Younghung Thermal Power Plant in the Republic of Korea. Toshiba started its business from a telegraph equipment factory in Tokyo in 1875, and is now a leading manufacturer of heavy electrical apparatus with a worldwide sales and service network. It has four major business areas: digital products, electric devises and components, social infrastructure systems, and home 12
appliances and others. Toshiba has delivered approximately 1,700 steam turbine units, 240 hydraulic turbine units, 300 hydraulic generator units, and 32 nuclear reactor units to customers throughout the world. It provides a vast range of turbine products, from several megawatt back-pressure turbines to over 1,000 MW supercritical 8 turbines. In February 1997, Toshiba reached the rare milestone of having produced turbine products with aggregate generating capacity of more than 100 gigawatts. Project construction will be managed with particular attention to coordination among the various contractors. An advisory council, be formed by industry experts, will assist with CGPL management, with support of Korea Power Engineering Company, Inc. The entire scope will handled by three project managers: (i) common facilities and unit 1, (ii) units 2 and 3, and (iii) units 4 and 5. Each project manager will cover engineering, procurement, and construction with support from, and coordination among, TCE, TPC's engineering and planning division, and the contractors. The Project is expected to be completed unit by unit. Commissioning of the first unit is expected by March 2011 and of the remaining units at regular 4-month intervals. The Project is expected to achieve full commercial operation by July 2012.
Coal Supply Up to 11.7 million tons of coal will be required per annum. The Government designed the Project with imported coal, and CGPL will source coal through long-term fuel supply agreements with exporters of coal in Indonesia, South Africa, Mozambique, and/or Australia, taking advantage of TPC's global coal procurement network. Despite the existing large domestic coal reserve, availability of domestic coal is not able to keep pace with the growing demand for coal for thermal generation. Under this circumstance, it is more economical to use imported coal for power plants on coastal locations, especially for those far away from the domestic coal mines. The main domestic coal reserves are in the eastern region of the country, and coal transport capacity is constrained. From the environmental perspective, the Government requires beneficiation before transporting high ash content coal over long distances. Hence, the Project, being set up on a coastal location, has been designated to use imported coal. The design of boilers would be dependent on the type of coal, and once designed for imported coal it is difficult to switch to domestic coal which has high ash content and lower calorific value. In terms of the choice of imported coal, it is important to procure quality coal with higher calorific value, lower ash, and lower sulfur. Lower ash content improves the overall plant availability due to lower maintenance requirements. Also, with higher calorific value, the Project would require less quantity of coal to generate the same level of output. To 13
achieve higher environmental standards, procurement of imported coal with lower ash and sulphur contents is essential.
Coal Transport CGPL will enter into a long-term time charter arrangement with bulk carriers for coal transport utilizing TPC's global fuel procurement network and capacity. TPC plans to set up a subsidiary to own vessels, and CGPL will enter into a time charter agreement with TPC's coal shipping subsidiary and/or directly with other shipping companies. Port Services Coal will be unloaded at Mundra Port. The concessionaire for the port, Mundra Port and Special Economic Zone Limited (MPSEZL), will provide port facilities as per the port service agreement between CGPL and MPSEZL. MPSEZL will make the terminal available and operate it to enable the minimum guaranteed tonnage to be unloaded and handled at the terminal. MPSEZL will ensure storage of at least 0.6 million t in the coal stack yard if required by CGPL. It will give berthing priority to CGPL's coal transport vessels, and make all arrangements for berthing of coal transport vessels. CGPL can also use the facilities at Mundra Port for unloading plant and equipment required for project construction. Transport of the coal from Mundra Port to the project site will be through a dedicated coal transport system. MPSEZL has agreed to provide the right-of-way for the corridor for the system, road access, and the seawater intake and discharge channel for the Project. Seawater Abstraction During operations, about 15.12 million m3/day of seawater will be used for condenser cooling and freshwater production. The spent cooling water and the reject from the desalination plant will be discharged back into the sea.
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Power Off take Agreements:
Power generated by the Project will be sold to distribution licensees of the states of Gujarat (excluding Ahmedabad and Surat Electricity Company), Maharashtra (excluding distribution companies in Mumbai), Punjab, Haryana, and Rajasthan.
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The seven offtakers that have signed power purchase agreements are: Gujarat Urja Vikas Nigam Limited The Gujarat Electricity Industry (Reorganization and Regulation) Act of 2003 restructured the Gujarat Electricity Board into seven entities with functional responsibility for trading, generation, transmission, and distribution. Gujarat Urja Vikas Nigam Limited owns 100% of the shares of the other six companies; and is responsible for bulk purchase and sale of electricity, supervision, coordination, and facilitation among the six subsidiary companies. Distribution licensees in Gujarat have a positive cash flow (including subsidy), and the deficit between average revenue and average cost is declining. However, the cross-subsidies have not changed. The substantial improvement in financial performance is mainly due to near 100% collection efficiency, reduced cost of supply because of operating efficiencies, and savings in interest costs because of debt restructuring. Maharashtra State Electricity Distribution Company Limited The Maharashtra State Electricity Board has been unbundled into four companies. In FY2006, Maharashtra State Electricity Distribution Company Limited had a negative cash flow (including subsidy) despite substantial profit in FY2004 and FY2005. The cross-subsidy has been steadily declining, indicating that a higher proportion of the cost of supply is being recovered from consumers. Collection efficiency is good, with more than 100% collection efficiency in FY2005, indicating that distribution licensees are recovering current dues and a portion of past dues. Generally, financial performance has improved. Punjab State Electricity Board (PSEB) Punjab state continues to follow an integrated model whereby all three functions of generation, transmission, and distribution are handled by PSEB. PSEB has reduced ATC losses considerably and achieved almost 100% cash collection. Its cash flow (including subsidy) has improved significantly with substantial profit in FY2004 and FY2005. During the same period, PSEB achieved a surplus between average revenue (including subsidy) and average cost. Thus PSEB performance is characterized by cash profit, dependence on subsidy from the state government because of the mid-level cross-subsidy, high collection efficiency, and relatively low ATC losses. 16
Haryana Power Generation Corporation Limited The Haryana State Electricity Board was one of the first SEBs to be unbundled along functional lines into a generation company, a transmission company, and two distribution companies. Subsequently, the trading function was separated from the transmission function. The generation company, Haryana Power Generation Company Limited, has been handling the trading and bulk purchase functions in the state since June 2005. On 14 August 1998, the transmission and distribution businesses were transferred to Haryana Vidyut Prasaran Nigam Limited. The Haryana Electricity Regulatory Commission regulates transmission and distribution. Power is wheeled through the entire network by Haryana Vidyut Prasaran Nigam Limited on the payment of transmission charges approved by the Haryana Electricity Regulatory Commission. Financial performance of the distribution licensees in Haryana are characterized by (i) not very sound cash flow positions, (ii) high dependence on subsidies, (iii) low collection efficiencies, and (iv) high ATC losses. Dependence on the state government subsidy is primarily a result of Haryana having a largely agrarian economy with state-subsidized power provided to agricultural consumers. As a result, the negative gap between average revenue (without subsidy) and average cost of supply has steadily increased. Rajasthan Power Procurement Centre It includes Ajmer Vidyut Vitaran Nigam Limited, Jaipur Vidyut Vitaran Nigam Limited, and Jodhpur Vidyut Vitaran Nigam Limited. The Rajasthan Power Sector Reforms Act of 1999 was enacted with effect from 1 June 2000, and accordingly the SEB was unbundled into five functional entities: one generation company, one transmission company, and three distribution companies: Jaipur Vidyut Vitran Nigam Limited, Ajmer Vidyut Vitran Nigam Limited, and Jodhpur Vidyut Vitran Nigam Limited. These distribution companies operate and maintain the electricity system below 66 kilovolts in their respective areas. As per the mandate of the 2003 Electricity Act, power purchase agreements (PPAs) and the procurement, bulk supply, and trading of power were transferred to the three distribution companies in February 2004. Financial performance of the distribution licensees in Rajasthan is characterized by negative cash flows, high dependence on subsidies, high collection efficiencies, high ATC losses, and a constant cross-subsidy. Dependence on the state government subsidy is primarily because the state government provides subsidies to various categories of consumers—mainly domestic and agricultural. The payment by each offtaker will be supported by an unconditional, irrevocable, and revolving letter of credit; and a default escrow account. If an offtaker defaults, CGPL has the option first to sell the power to 17
the other offtakers and second to third parties. The liability of the defaulting offtaker to make capacity charge payments to CGPL will remain unaffected for up to 3 years of capacity charges (to the extent not paid by another offtaker). If the total offtake is less than the minimum guaranteed offtake of 65%, and CGPL has paid the penalty for not purchasing the minimum quantity of fuel, CGPL is entitled to receive compensation for such penalty from the offtakers that didn’t meet the guaranteed minimum offtake. The offtakers are responsible for procuring the transmission facilities beyond the Project's 400 kilovolt switchyard bus bar under the PPA. Power from the Project will be evacuated by a dedicated transmission line to connect the Project with the grid system operated by Power Grid Corporation of India Limited. Operation and Maintenance CGPL’s in-house engineers will be responsible for project operation and maintenance with support from TPC. The key personnel of the operation and maintenance team will be deputed from TPC and its affiliates, and have expertise in thermal power engineering. Other operations personnel, with strong expertise and experience, will be recruited from outside. CGPL has recently tied up with Texas-headquartered Invensys Operations Management, to optimise India's first ultra-mega 4000MW power plant located in Mundra. Invensys will provide distributed and critical control systems, emergency shutdown systems, advanced process control, plant optimization and operator training simulator technology. The scope of the project includes the provision of end-to-end solutions, from boiler management systems to turbine auxiliary controls, with interfaces for seamless systems integration with other technology vendors. CGPL can immediately leverage the global expertise and engineering capabilities of Invensys, giving them the assurance of proven delivery capability and commitment to train Coastal Gujarat's operators.
Fuel Oil Transport The total consumption of fuel oil will be about 50,000 kiloliters per annum during uncanning operations. The fuel oil will be sourced from refineries in Jamnagar and Vadodara, etc., and will be transported to the power plant by rail or road tanker. The fuel oil will be stored in three tanks, two with 10,000 cubic meter (m3) capacity and one with 5,000 m3 capacities.
Ash Transport and Storage 18
The power plant will produce about 1.8 million MTPA of ash, of which bottom ash accounts for about 20% and fly ash 80%. Bottom ash collected in the bottom ash hopper below the boiler furnaces will be conveyed by jet pump up to the ash slurry sump for further disposal in wet form. Fly ash collected at various hoppers will be conveyed pneumatically to fly ash storage silos. Air vented out from the silos will pass through suitable control devices to remove fugitive fly ash. The dry fly ash collected in the fly ash silos will be given to fly ash users, and the remaining quantity will be disposed off in wet form. The Project has allocated about 241 ha of land for ash disposal. However, most of the ash will be utilized. Closed trucks will be used to haul the ash to utilization points.
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Economic Outlook-Indian Economy
The Indian economy entered the financial year 2008-09 on a buoyant note. During the preceding three years, the country had, witnessed tremendous economic growth with Gross Domestic Product expanding at an average of 9 per cent. However, the growth momentum was moderated because of the global economic conditions. Like all other emerging economies, India too was impacted by the credit crisis. The slowdown in growth was reflected in lower industrial production, negative exports, deceleration in services activities, dented corporate margins and diminished business confidence. As per the revised estimates for the FY 2008-09, the GDP for the year grew at 6.7 per cent as against 9.1 per cent in the previous year. But there were some comforting signs too. Well-functioning financial markets, robust rural demand, lower headline inflation and robust foreign exchange reserves were all pointers to the long term strength and resilience of the Indian Economy. The timely fiscal stimulus packages announced by the Government coupled with swift monetary easing and regulatory action by the Reserve Bank of India, helped to arrest the slow down and keep the economy ticking. The global situation saw some easing, thanks to an unprecedented and coordinated policy action by authorities across major economies of the world. Recently announced figures indicate a 10.2% growth in IIP (October 2009, YoY) which reinforces the subdued but strong growth that the Indian economy will witness. However, interest rates may be tightened going into the future because of concerns over demand-led inflation.
Power Generation in India
India is the world’s 6th largest consumer of energy, with a share of 3.4% in the world. Demand for energy is growing in India due to the rising economic prosperity of the country. The major portion of energy needs in India is met through vast coal reserves. Recent developments are increasing investments in renewable sources of energy. The total power generation in the country during FY09 was 723.55 Billion Units as against the target of 774.34 BUs, about 6% below target. The installed generation capacity in the country as on 31st March, 2009 was 147,965 MW.
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India has been traditionally dependent on thermal power as a source of power generation, which constitutes about 63 per cent of the current capacity. The balance is contributed by hydroelectric power (25 per cent), nuclear (3 per cent), and renewable energy (9 per cent). The western region accounts for the largest share (31 per cent) of the installed power generation capacity in India followed by the southern region with 27 per cent and the northern region with 26 per cent. The southern region remains the dominant region in renewable energy source accounting for more than 53 per cent of the total renewable energy based installed capacity.
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Fuel Availability Thermal coal requirement of power plants is projected to be 549 Million tonnes in 2012, against which domestic production is expected to be 482 MT. The shortfall can be covered by imports, which are expected to grow steadily from 20 MTPA in FY08 to over 60 MTPA by FY12. Projects that have already been allotted coal linkages are still unable to get a firm commitment on actual supply.
The pie chart below represents the power generation mix by ownership indicating highest generation by State boards of 52% followed by Central (33%) and Private Parties (15%).
The increase in installed power generation capacity has however not kept pace with the increase in demand for power thus leading to power shortages. The per capita consumption of electricity increased from 15 kwh in 1950 to 704 kwh in FY 2007-08, which however continues to be very low in comparison to other developed and developing countries. The gap in demand and supply has led to significant shortages as can be seen from the figures of financial year 2008-09:
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Latest Developments in Power Sector • CERC's 2009-14 Regulations With an objective of making investment in generation and transmission infrastructure more attractive without compromising consumer interest, on January 19, 2009, CERC announced tariff regulation for power generation and transmission for 2009-14. The key high lights are as under: • The base rate of Return on Equity is raised from 14% (post tax) to base rate of 15.5% to be grossed up with normal tax rate as applicable to the concerned utility. There is an additional 0.5% Roe if projects are commissioned within given time-lines. • To boost the hydro power sector, CERC has insulated new hydro projects from shortfalls in generation resulting from hydrological factors for a period of 10 years after COD. If there is an energy shortfall the energy charge for the following year would be computed on the basis of actual power generated rather than designed power generation. • • • For hydro plants Normative Annual Plant Availability Factor (NAPAF) fixed. Advance against depreciation removed. Depreciation rates to be calculated annually using straight line method as per Companies Act. The salvage value of assets fixed at 10%. After initial 12 years, the remaining depreciation to be spread over the rest of useful life of the asset.
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O&M expenses recoverable on normative basis for thermal and hydro plants. For transmission systems, O&M costs would be calculated by multiplying number of bays and Kilometers of line length with the benchmarks set for the year.
• • • • • • • •
The availability targets for thermal power plants are raised from 80% to 85% to recover fixed costs. Incentives linked to plant availability factor instead of PLF for thermal plants. Normative auxiliary consumption reduced in certain unit sizes. Reduction in normative heat rate for units of 500 MW size Recovery of capacity charge, energy charge, transmission charge and incentives would be based on operational performance. The norm for secondary oil consumption reduced from 2 ml per unit to 1 ml per unit, the savings in secondary oil consumption are to be shared with the beneficiaries in the 50:50 ratios. Generation / Transmission project developer can retain 100% carbon credits in the first year following the date of commercial operation. Generation/Transmission companies can hedge foreign exchange exposure with respect to interest on foreign currency loans and repayment of loan. Recovery of the cost of hedging and foreign exchange variation to be made directly without any application to the CERC.
• Competitive bidding tariff guidelines amended Ministry of Power in January 2005 issued guidelines for tariff determination through bidding for procurement of power by distribution licensees with an objective to facilitate transparency and fairness in the procurement process, facilitate reduction of information asymmetries for various bidders and protect consumer interest by facilitating competition. The guidelines have been recently amended to encourage sale of electricity outside the ambit of long term PPAs. Key highlights of the amendment: 1. Guidelines will be applicable for 15% of the new generating capacity which may be sold outside long term PPAs to promote market development. 2. Separate Request for Proposal (RFPs) to be invited for base load and peak load and seasonal load requirements. 3. Provision for multi-part tariff for procurement under Case 2 bidding.
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4. Hydro power tariff can be determined by the SERC provided 60% of the total saleable energy is committed to a long term PPA. • Amendment to short term inter-state open access regulations With the objective of streamlining and rationalizing inter-state open access, the following provisions have been made by CERC: • In case the State Load Dispatch Centre does not give concurrence to an inter-state open access proposal in 7 working days on first occasion and 3 working days on subsequent occasion, the concurrence of the LDC shall be deemed to have been given. • • • • • The State Load Dispatch Centres will check only two parameters i.e. availability of transmission capacity and availability of metering infrastructure. Open access customer can now request for change in schedule at notice of two days instead of the presently provided period of five days. The transmission charges for short-term open access have been rationalized. Charges on short-term open access will be disbursed directly to the long term customer by RLDC instead of routing the same through Central Transmission Utility. All disputes under inter-state access regulation to be decided by CERC.
• R-APDRP Accelerated Power Development and Reforms Programme (APDRP) were launched in X Plan by Govt. of India. This programme was modified and renamed as Restructured APDRP (R-APDRP) in 2007-08. The R-APDRP is linked to actual demonstrable performance in terms of AT&C loss reduction to 15% or less by the end of XI plan. Establishment of reliable automated systems for collection of accurate baseline data and the adoption of information technology in the areas of energy accounting are necessary preconditions for sanctioning of projects for strengthening and up-gradation of sub-transmission and distribution network. It also includes adoption of IT applications for meter reading, billing and collection, energy accounting and auditing, management information systems, redressal of consumer grievances and establishment of IT-enabled consumer service centres, besides asset mapping of the distribution network. Since its launch, the R-APDRP has made rapid headway and by February 2009, had sanctioned 599 projects in various towns and cities at a cost of Rs. 19.5 billion. Andhra Pradesh, Karnataka and Rajasthan together account for over 55 per cent of the total amount sanctioned so far. AT&C losses are showing a declining trend and have come down from 38.86% in 2001-02 to 33.07% in 2006-07. 25
Rural Electrification As per Central Electricity Authority (CEA), over 82% villageshave has been electrified. The Central Govt. launched a scheme "Rajiv Gandhi Grameen Vidyutikaran Yojana" (RGGVY) in April2005 with the goal of electrifying all (around 125000) villages and hamlets and providing access to electricity to all households in next five years. Under RGGVY, 59,882 villages have been electrified and connections to 53.78 lakh BPL households have been released up to 31.3.2009. (Source: Economic Survey 2008-09) • 100 days Agenda There has been a concerted effort to ensure that development in Power sector is not derailed. For the short term, a 100 days agenda has been drawn by MoP with a capacity addition target of 5,653 MW. Also, a high level committee /group has been set up to monitor ongoing projects and ensure their timely commissioning
Transmission and Distribution Power transmission was recognized as a separate activity and opened up to private investment in the late 1990s with several structural reforms and the unbundling of State Electricity Boards. There was an increased focus on power transmission, both by planners and by private investors after the Electricity Act, 2003 was passed. The rate of growth of the transmission network (at voltages of 220 kV and above) during the past decade has been at about 6 – 7% per annum. The inter-regional transmission capacity has increased from 5,050 MW at the end of the Ninth Plan to 20,750 MW by March 2009. However, this still falls short of the target of 14% per annum growth in transmission capacity for the Eleventh Plan. The Government policy plans to increase inter-regional transmission capacity to 58,700 MW by 2015. It is expected that thereafter, inter regional transmission will not be a constraint. The distribution network has grown from 5.73 million circuit kms in 2002 to 6.61 million Circuit kms in 2008. The target is to enhance network length to at least 7.58 million Circuit Kms by 2012. Consumer base has increased from 122 million in 2002 to 152 million in 2008. Power distribution still remains a segment that needs significant reforms, as this would have a direct impact on the sector’s commercial viability and ultimately on the consumers. The sector has been plagued by high distribution losses with low cost recovery, resulting in poor financial health of utilities. With Accelerated Power Development and Reforms Programme (APDRP), many initiatives have been introduced to reduce Aggregate Technical 26
and Commercial (AT & C) losses by modernizing distribution infrastructure. Losses in the form of theft, however, can only be eliminated through strong political will.
Power Trading Organized power trading started in India after the enactment of EA 2003. EA 2003 recognized trading as a distinct licensed activity and provided for non-discriminatory open access to generators, consumers and licensees. Tata Power Trading Company Limited was the first company to be granted license by CERC in June 2004. Presently, there are 43 licensed traders, of which the active players are TPTCL, PTC India Limited, NTPC Vidyut Vyapar Nigam Limited, Adani Enterprises Limited, Reliance Energy Trading Limited, Lanco Electric Utility Limited and JSW Power Trading Company Limited. In FY09, 32,200 MUs of energy was traded in the country, which constitutes only 4.45% of the total power generated. Power trading fulfills an important need of both consumers and generators to buy and sell power as and when needed at the prevailing market rates. Given the right policy and regulatory initiatives, such as a review of the cap on trading margin, the power trading industry has a good potential to prosper and serve the needs of the consumers in India. Introduction of Power Exchanges A Power Exchange is a fully electronic platform which facilitates buying and selling of power by members in a transparent and anonymous manner at the market discovered rates. CERC issued guidelines for setting up and operation of Power Exchanges in India. Indian Energy Exchange Limited (IEX), in which the Company is a shareholder, was the first exchange to start operations on 27th June, 2008. Power Exchange India Limited (PXI), the second power exchange promoted by National Stock Exchange of India Limited and the National Commodity and Derivatives Exchange Limited, became operational on 22nd October, 2008. In FY09, 2,628 MUs were traded on IEX and 149 MUs were traded on PXI. Development of Renewable Energy Sources (RES) for generation of power RES of 13,242 MW accounting for 9% of total installed capacity is targeted to grow to over 24,300 MW contributing to 11% of fuel basket by 2012. Over the longer term, its importance would be more strategic in view of its important role in mitigating the effects of climate change. It is imperative for India to build a certain level of self-reliance in renewable technologies of the future. The Government, in its quest for long-term energy and environmental security, is seeking to enhance the share of power from renewable sources in the overall fuel basket. India has potential for 45,000 - 65,000 MW of on shore wind power.
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70% of renewable energy is contributed by wind power generation. During past one year, solar energy, which currently contributes a little over 2 MW to the grid, received a significant boost with the National Action Plan for Climate Change mandating the setting up of a National Solar Mission. The mission is targeting 20,000 MW of solar based capacity by 2020. The steps taken by Govt. for increasing generation from renewable energy resources are: • EA 2003 requires SERCs to specify a percentage for purchase of electricity from cogeneration or renewable sources termed as Renewable Purchase Obligation (RPO). SERCs in 12 States have already specified the percentage -Andhra Pradesh, Gujarat, Karnataka, Madhya Pradesh, Orissa, Rajasthan, Tamil Nadu, Kerala, Haryana, Maharashtra, Uttar Pradesh and West Bengal. • Tariff Policy provides for competitive bidding for procurement of power from such sources - bidding to be done amongst suppliers offering power from same type of renewable source. • Procurement of power at preferential tariffs to be allowed by SERC. • Special scheme by MNRE for promoting solar power and plans for Generation Based Incentives under National Solar Mission. • CERC is in the process of finalization of regulations for sale of power generated based on RES Problems faced for development of RES • Power generation from renewable increases the uncertainty in accurate availability of power which in turn affects grid reliability and operations. • The developer of renewable generation has to provide for transmission line for power evacuation from the plant to the nearest HT Sub-station unlike conventional plants where transmission utility evacuates power. • The PPA for renewable requires the developer to guarantee the supply of a certain quantity of electricity. However, it does not require the transmission utility to provide any guarantee for grid availability. • The wind generation requires back-up capacity between the forecast and actual generation posing difficulty in open access and scheduling the power. Wind energy has separate grid codes in major wind based power generating countries. A draft grid code is under development for wind power.
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Opportunities and Outlook To achieve the Eleventh Plan targets, India needs over 65.86 GW of generation capacity addition by 2012. If this is to be achieved, it would need multiple initiatives in generation, transmission and distribution. The steady rise in demand for power as a result of economic growth is expected to present the Company with a number of opportunities. Some of these opportunities are discussed below: Opportunities in Generation The inability to add adequate generation capacity has resulted in India facing increasing power shortages every year. The Government policy thus far has only focused on adding base load generation capacity. As the standard of living improves, the demand in peaking power will increase faster than the demand for base load power. At the same time, the base load power requirement itself is expected to rise. Hence, there will also be a number of opportunities for building power plants near load centers. To expedite the target growth of power generation, the Government of India has identified the development of Ultra Mega Power Projects (UMPPs) as a thrust area. The central idea of the UMPP is to set up generation capacity on a large scale and reduce the development time of the project with the Government arranging land and all key approvals for the project. So far, four such projects of 4,000 MW capacities each have been awarded and more are planned.
Opportunities in Transmission Plans to boost transmission capacity have generally fallen short of the targets set in the Eleventh Plan. There is now a move to increase the inter-regional transmission capacity by the end of the Eleventh Plan to 37,700 MW from 20,750 MW7. Greater private sector participation is expected in the future with private developers taking an integrated approach to generation and transmission for timely evacuation of electricity from their generation projects. With use of advanced technology in transmission, there is improvement in voltage levels and grid discipline. The Government targets to attract private investment of Rs. 20,000 crores in the inter-state transmission system during the current plan period. To boost private investment in the transmission sector, the Government is developing large transmission projects through tariff based competitive bidding, based on the successful model of the UMPPs and has appointed Power Finance Corporation Limited and Rural Electrification Corporation Limited to oversee their implementation. These initiatives are expected to present the Company with opportunities. 29
Opportunities in Distribution While India has the third largest transmission and distribution network in the world, large parts of the population still have to make do without electricity or with frequent power cuts and fluctuating voltage. The regulators have played a significant role in creating an enabling environment for improving levels of service through private investment. The Central Government has introduced the APDRP to provide finances to the states to modernize distribution infrastructure. The franchisee model has been introduced recently and provides room for private sector participation in distribution. Growing commercial orientation and consumer focus along with a strong policy environment are expected to act as key drivers to shape the future outlook of distribution. As and when the distribution sector is opened up for a larger role for the private sector, it will provide a large and profitable opportunity. The Company, with its experience of distribution through its subsidiary North Delhi Power Limited (NDPL) and its own network in Mumbai, is well poised to exploit these opportunities.
Electricity Act 2003:
It came into existence in order to take favourable measures of development of electricity industry. It consolidates all the processes related to electricity generation which include generation, transmission, trading and use of electricity. The act is conducive to the growth of all the parties. It protects the interest of consumers, rationalization of electricity tariff, ensuring transparent policies regarding promotion of subsidies, promotion of efficient and environmentally benign policies constitution of Central electricity authority, regulatory commissions and promoting competition therein. Salient features of the act are: Role of government, rural electrification, generation, transmission, distribution, consumer protection, trading/market development, regulatory commission/appellate tribunal, tariff principles, CEA, measures against theft of electricity, restructuring of SEB’s. Central government prepared the National Electric Policy which is aimed at a supply of reliable and quality power of specified standard in an efficient manner and at reasonable rates and protection of consumer interests. Objective of Tariff Policy is to promote competition, efficiency in operations and 30
improvement in quality of supply and ensure availability of electricity to consumers at reasonable and competitive rates.
Ultra Mega Power Projects (UMPPs)
The Indian Government had envisaged a capacity addition of about 100 GW to meet its mission of ‘power to all by 2012’, though the target addition, for 11 th FYP, was subsequently revised downwards to about 65 GW. The need for capacity addition was, and continues to be, so huge that it was not going to be feasible from the ongoing projects. There was a need to develop large capacity projects at the national level to meet the requirements of a number of states under the competitive bidding guidelines dispensation. This gave a thrust to development of projects through competitive bidding. Ultra Mega Power Projects are steps in that direction. The proposed nine UMPPs will go a long way in substantial reduction power shortage in India. The Government proposed use of latest super critical technologies in these large power projects to achieve economies of scale leading to cheaper power. Use of Super Critical Technology was also with a view to achieve green-house gas emissions and flexibility in unit size, the latter being subject to adoption of specified minimum supercritical parameters. Various ministries and government agencies are working in tandem in successful pursuit of UMPPs, at the earliest. These UMPPs, each having a capacity of minimum 4,000 MW, would also have the scope for future expansion. These large sizes projects were to meet the power needs of a number of states through transmission of the generated power on regional and national grids to load centres. In order to enhance investor confidence, reduce risk perception and receive a good response to competitive bidding, it was deemed necessary to provide the site, fuel linkage in captive mining blocks, water, environment and forest clearance, and to make substantial progress on land acquisition ultimately leading to possession of land, and all these activities were to be done through a Shell Company. The Shell Company, in addition, would also be responsible for tying up necessary inputs from the likely buyers of power, tying up of power off takes from these projects, with appropriate terms and conditions and Payment Security Mechanism, with procurers of different states.
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The development of Ultra Mega Power Projects (UMPPs) has long been identified as a thrust area. These projects, approximately 4000 MW each, would involve an estimated investment of about Rs. 16,000 to 20,000 crores each. These projects will meet the power needs of a number of States/ distribution companies located in these States (and in states in the vicinity), and are being developed on a Build, Own, and Operate (BOO) basis. In view of the fact that promotion of competition is one of the key objectives of the Electricity Act, 2003, and of the legal provisions regarding procurement of electricity by distribution companies, identification of the project developer for these projects is being done on the basis of tariff based competitive bidding. Guidelines for determination of tariff for procurement of power by distribution licensees have been notified in January 2005 under the provisions of the Electricity Act, 2003. Power Finance Corporation (PFC) has been identified as the nodal agency for this initiative. Integrated power project would have dedicated captive coal blocks for pithead projects. Coastal projects, on the other hand were supposed to use imported coal. This was to ensure adequate supply of coal for other domestic power producers/ industries (for which using imported coal would not be feasible due to prohibitive inland transporting costs). Besides, coastal location of UMPPs made it feasible to import coal on account of economical transportation facilities of better quality coal available from mines in Indonesia, South Africa, Australia, etc. The Bidding Process: For these projects, as per the provisions of the competitive bidding guidelines, a two stage selection process has been adopted. The first stage of bidding involves Request for Qualification (RfQ) containing qualifying criteria for selection of bidders. The RfQ documents submitted by the bidders are evaluated to identify those bidders who will be eligible to participate in the second stage of the process. The second stage of the bidding process invites Request for Proposals (RfP) from the bidders so qualified. After evaluation of the RfP documents, the successful bidder is identified on the basis of the lowest levelised tariff.
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In addition to these sites, additional sites have been identified/ suggested by Tamil Nadu (Marakanam) and Karnataka (Ghataprabha). The Central Electricity Authority is in the process of examining the feasibility of these sites for development of UMPPs.
The SPV or Shell Company is incorporated as a 100% subsidiary of PFC. Upon completion of the entire process for selection of the project developer the SPVs are transferred to the selected bidders i.e. to the selected project developers. Role of SPVs The SPVs are responsible for carrying out various activities on behalf of the procurers. Completion of these activities prior to award of the project is considered necessary to enhance the investor’s confidence, reduce risk perception and get a good response to the competitive bidding process. Some of the main activities undertaken by the SPVs include Appointment of Consultants to undertake preparation of Project Report, preparation of Rapid Environment Impact Assessment Report etc., Appointment of Consultants for International Competitive Bidding (ICB), document preparation & evaluation, To finalise RfQ/ RfP documents in consultation with States / bidders, To carry out RfQ/ RfP process and award of project, Acquisition of land for the project, Obtaining Coal blocks for pit-head projects, Getting clearance regarding allocation of water by the State Govt. for pithead locations, Approval for use of sea water from Maritime Board/ other Govt. Agencies for coastal locations, Obtain clearance from the State Pollution Control Board, initiate forest clearance etc. as are required for the project and for the coal mines, followed by environment and forest clearances from the Central Government, Obtaining geological reports/ other related data from CMPDI for the coal blocks, and Tie up the off-take/ sale of power. Role of the Ministry of Power The Ministry of Power is playing a crucial role for the development of the UMPPs by coordinating between various concerned Ministries/Agencies of the Central Government, and with various State Governments/Agencies. The key areas requiring the Ministry of Power’s intervention include Coordination with Central Ministries/Agencies for ensuring Coal block allotment/coal linkage, Environment/forest clearances, Water linkage, Required support from State Governments and their agencies, Working out allocation of power to different States from UMPPs in consultation with the States, Facilitating PPA and proper payment security mechanism with State Governments/State Utilities, and Monitoring the progress of Shell companies with respect to predetermined timelines.
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National Electricity Plan The Electricity Act 2003, requires CEA to lay out the National Electricity Plan once in every 5 years and revise the same from time to time in accordance with the National Electricity Policy. This plan serves as a roadmap towards optimum growth of the power sector. Under this, CEA formulates short term and prospective plans for the development of electricity systems and coordinate the activities of the various planning agencies for the optimal utilisation of resources to serve the interests of the national economy Role of States States hosting the UMPPs and the other power procuring States are also required to play a pro-active role. Some of the activities in which the concerned States play a decisive role include implementation of the Rehabilitation & Resettlement Plan, provide authorization to the PFC/SPV to carry out the bidding process on behalf of the distribution utilities, participate through its representatives in various committees set up for undertaking the competitive bidding process, facilitate signing of the Power Purchase Agreement, ensure proper payment security mechanism with the distribution utilities etc.
Financing of the project The financing of the Mundra UMPP in India created a number of precedents. The financing represents the single largest foreign debt and the largest limited recourse financing to date in India; the largest financing ever done for a power plant in India; and the largest ever financing by the IFC. It is also the single largest facility by the Korean Exim Bank and Korea Export Insurance in India, and the first private sector power project in India to be based on energy efficient supercritical technology.
CDM PROJECT:
The Clean Development Mechanism (CDM) is an arrangement under the Kyoto Protocol allowing industrialized countries with a greenhouse gas reduction commitment (called Annex 1 countries) to invest in ventures that reduce emissions in developing countries as an alternative to more expensive emission reductions in their own countries. A crucial feature of an approved CDM carbon project is that it has 34
established that the planned reductions would not occur without the additional incentive provided by emission reductions credits, a concept known as "Additionality". The CDM allows net global greenhouse gas emissions to be reduced at a much lower global cost by financing emissions reduction projects in developing countries where costs are lower than in industrialized countries. The CDM is supervised by the CDM Executive Board (CDM EB) and is under the guidance of the Conference of the Parties (COP/MOP) of the United Nations Framework Convention on Climate Change (UNFCCC) Under this mechanism Certified Emission Reduction Certificates are sold to entities in Annex 1 countries which have to achieve Emission reduction targets. India is a Party to the United Nations Framework Convention on Climate Change (UNFCCC) and the objective of the Convention is to achieve stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.
THE KYOTO PROTOCOL:
The Kyoto Protocol is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC or FCCC), aimed at combating global warming. The UNFCCC is an international environmental treaty with the goal of achieving "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. The Protocol was initially adopted on 11 December 1997 in Kyoto, Japan and entered into force on 16 February 2005. As of November 2009, 187 states have signed and ratified the protocol. The most notable non-member of the Protocol is the United States, which is a signatory of UNFCCC and was responsible for 36.1% of the 1990 emission levels. Under the Protocol, 37 industrialized countries (called "Annex I countries") commit themselves to a reduction of four greenhouse gases (GHG) (carbon dioxide, methane, nitrous oxide, sulphur hexafluoride) and two groups of gases (hydrofluorocarbons and perfluorocarbons) produced by them, and all member countries give general commitments. Annex I countries agreed to reduce their collective greenhouse gas emissions by 5.2% from the 1990 level. Emission limits do not include emissions by international aviation and shipping, but are in addition to the industrial gases, chlorofluorocarbons, or CFCs, which are dealt with under the 1987 Montreal Protocol on Substances that Deplete the Ozone Layer.
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The benchmark 1990 emission levels were accepted by the Conference of the Parties of UNFCC were the values of "global warming potential" calculated for the IPCC Second Assessment Report. These figures are used for converting the various greenhouse gas emissions into comparable CO2 equivalents when computing overall sources and sinks. The Protocol allows for several "flexible mechanisms", such as emissions trading, the clean development mechanism (CDM) and joint implementation to allow Annex I countries to meet their GHG emission limitations by purchasing GHG emission reductions credits from elsewhere, through financial exchanges, projects that reduce emissions in non-Annex I countries, from other Annex I countries, or from annex I countries with excess allowances. Each Annex I country is required to submit an annual report of inventories of all anthropogenic greenhouse gas emissions from sources and removals from sinks under UNFCCC and the Kyoto Protocol. These countries nominate a person to create and manage its greenhouse gas inventory. Power sector is the most prominent sector contributing in the pollution
Central Electricity Regulatory Commission (CERC):
The Commission intends to promote competition, efficiency and economy in bulk power markets, improve the quality of supply, promote investments and advise government on the removal of institutional barriers to bridge the demand supply gap and thus foster the interests of consumers. As entrusted by the Electricity Act, 2003 the Commission has the responsibility to discharge the following functions : Mandatory Functions:• • To regulate the tariff of generating companies owned or controlled by the Central Government To regulate the tariff of generating companies other than those owned or controlled by the Central Government specified in clause (a), if such generating companies enter into or otherwise have a composite scheme for generation and sale of electricity in more than one State; • • To regulate the inter-State transmission of electricity To determine tariff for inter-State transmission of electricity 36
•
To issue licenses to persons to function as transmission licensee and electricity trader with respect to their inter-State operations
•
To adjudicate upon disputes involving generating companies or transmission licensee in regard to matters connected with clauses (a) to (d) above and to refer any dispute for arbitration
• • •
To levy fees for the purposes of the Act To specify Grid Code having regard to Grid Standards To specify and enforce the standards with respect to quality, continuity and reliability of service by licensees
• •
To fix the trading margin in the inter-State trading of electricity, if considered, necessary To discharge such other functions as may be assigned under the Act.
Advisory Functions:• • • • Formulation of National electricity Policy and tariff policy Promotion of competition, efficiency and economy in the activities of the electricity industry Promotion of investment in electricity industry Any other matter referred to the Central Commission by the Central Government
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Key Risks
? Operational Risk ? A Super Critical technology based power plant is yet to be operational in India. Roping in of efficient & experienced operators will be critical in managing risks of Mundra UMPP ? Timely availability proper port infrastructure at Mundra is critical and delay on that account will directly affect fuel supply for the coastal plant. ? Completion Risk ? Risks of project getting delayed and/or of Cost overruns are too critical to be overemphasized. Only experienced contractors, and sub-contractors thereof, must be entrusted with the task. ? Regulatory Risk ? Export limits of coal set by Indonesian Government, if any, might pose a potential risk to uninterrupted fuel supply to GCPL. ? MAT (Minimum Alternate Tax, controlled by Central Government) ? CER Rate Volatility Risk ? Prices of Certified Emission Reductions are prone to fluctuation, based on, inter alias, supply-demand, economic cycles, implementation of Kyoto protocol. Besides, the Rupee value of CER-based revenue will also be impacted by exchange rate of Indian Rupee. ? Financial Risk 38
? Interest Rate Risk: Loans by international agencies, both multilateral as well as bilateral lending, will be floating rate loans linked to some benchmark like USD denominated LIBOR. An increase in interest rate will also increase their interest payments on rupee denominated term loan from Indian Financial Institutions. ? Currency Risk ? Rupee depreciation: Depreciation of Rupee will impact the SPV through at least three channels. The financial performance of GCPL, with respect to payments to be made to EPC contractors, repayment of interest and principal on foreign currency loans and receipt of revenues for generation of CERs, are inextricably linked to strength of the Indian Rupee vis-à-vis other Global Currencies.
Risk Matrix
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Risk Assessment & Risk Mitigation
? In June 2007, Tata Power acquired a 30% stake in two coal mines in Indonesia to hedge the fuel supply risk for its Mundra UMPP project ? The acquisition has turned out to be meaningful, since Tata Power has enjoyed returns from higher coal prices by earning dividends from the coal mines until the commissioning of the Mundra UMPP project
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? The political and regulatory environment pose a threat to our assumptions, but we believe that the coal contracts of work (CCOW), under which the company operates provide a partial hedge to this risk ? Mundra Port and SEZ Ltd are planning a 35MT per annum terminal by 2010 and any delay in its execution could lead to fuel supply concerns. However, the total demand for 12–13MT per annum of imported coal is likely to be required only in 2013, by which time, we believe the coal terminal will be ready
? A delay in the execution of projects, would pose increased capital cost risk, owing to accumulated interest during construction, which would affect earnings. ? The company has already awarded contracts for its projects under execution and, hence, we believe delays in equipment supply would be highly unlikely. ? Since Tata Power placed orders with Toshiba and Doosan immediately after the project was awarded, we believe timely supply is likely and cost overruns can be avoided despite the significant volatility in commodity prices over the past year, as the main equipment supplier would have been able to hedge by forward buying for this project ? To hedge against varying shipping costs, the company is planning to acquire ships for coal transportation through a wholly owned subsidiary based in Singapore (this move could help it obtain tax incentives that are to shipping companies). In addition, shipping prices have fallen in the recent past, providing Tata Power the opportunity to charter ships for the long term at reasonable rates. We assume Tata Power’s average transportation cost to be INR750 per tonne for the project life led by both the acquisition and chartering of ships. ? Largest ever power plant in India with significant implementation risks including delays and cost overruns ? Key technology supplied by reputable contractors at fixed price; adequate contingencies and sponsor support for cost overruns and delays ? Fuel supply risks from imported coal could expose Project to volatility in coal pricing ? Long term coal supply contract at reasonable prices; Coastal Gujarat Power Limited plans to further diversify coal sources
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? Delays in completing the requisite transmission lines and port infrastructure ? Transmission & port infrastructure developed by reputable companies with good track record ? Off-take risks from poor creditworthiness of the state-owned utilities ? Project’s tariff is highly competitive; ensures that state utilities are incentivized to pay; power sector reforms progressing in most Indian states ? Refinancing risks after 10 years of operations because of insufficiently long tenors from local banks ? IFC and other foreign lenders providing long-term loans with 20 year tenor which will help mobilize other commercial lenders when needed ? CER price volatility in the international markets subjects the project to the risks of fluctuating gains arising out of sale of CER’s ? This risk mitigation mechanism is not freely available in the market and thus it cannot be effectively mitigated
Conclusion
The Project is a green-field project initiated in response to the Government’s energy policy. Its large capacity and use of super-critical technology, and coal as its primary fuel, make it the most cost-effective alternative for generating electricity to meet the demand backlog and support further economic growth in the state and the country. The power plant and its support facilities will be constructed on a marginal land 42
that is not ecologically or culturally sensitive. The power plant will adopt supercritical steam technology, which is about 10% more efficient than a conventional, subcritical coal-fired power plant. The Project will have no major ecological impacts, as it will adopt the best practicable mitigation measures and technologies to minimize emissions and impacts on the environment. The Project will require the contractors to adopt best environmental management practices during construction to minimize environmental disturbances such as emissions from heavy construction equipment and trucks, noise, and dust. Residual impacts will not reach the two nearby villages. Contractors will provide appropriate training to their workers in environmental, safety, and health aspects of construction, and will provide necessary protective measures to workers to minimize safety risks. The Project will adopt the best process technology and designs as well as effective pollution control equipment to minimize emissions during operations. Emissions will meet national standards as well as World Bank emission guidelines for new power plants. Impacts on ambient air quality have been found to be insignificant.
After thorough evaluation, based on risk assessment, financial viability and other associated benefits/ concerns, we recommend the project to financers.
Financials
Key Assumptions
Capacity Commisioned(MW) Completion year Fiscal Year Completion Days Operational 43
Phase
1 2 3 4 5 Project Size (MW)
800 800 800 800 800 4000
Sep-11 Jan-12 May-12 Sep-12 Jan-13
Mar-12 Mar-12 Mar-13 Mar-13 Mar-13
210 90 330 210 90
Operating Assumptions Fuel Cost Rs / ton Coal Consumption rate Kg/kWh Coal cost Rs/unit Transportation & handling costs of coal / gas O&M Expenditures (3rd Year post COD) Annual Dollar Rate 2250 0.36 0.81 0.22
50 46
Plant Load Factor (PLF) Auxialary Consumption Tariff (Rs / Kwh) Annual Tariff Escalation in percentage Useful Life (years)
85.00% 8.00% 2.26 0.00% 25
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Grid Emission Factor (GEF) Co2 savings in 10 years in Million Tonnes CER Rate (Euro / CER) Exchange Rate (Rs / Euro) CER Rate (Rs / CER) Working Capital Assumptions Receivables (months) O&M Expenses (months)
Savings that will be made by using this critical technology in terms of CO2 or CER 28.30 12 66 792
2 1
D/T Financial Assumptions Debt Equity Total Project Cost (Rs Million)
0.75 Total Requirement 127500 42500 170000 FY09 FY10 FY11 FY12 1275 1275 0 0 4250 4250 1700 1700 0 0 FY13 76500 25500 102000
12750 12750 4250 4250 1700 1700 0 0
Debt Structure Korean Bank, ADB,IFC (in Billion Dollars) SBI(In $ Billion) Interest On Debt Repayment Period for SBI (yrs) Repayment Period for Foreign Dev. Bank (yrs) Moratorium period (Years) Cost of Equity
Interest rates 67734.3 75 59765.6 25 12.7% 12 20 3 18% 12.0% 13.5%
Depreciation (% p.a.) Estimated Salvage Value Tax Rate
3.60% 10%
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MAT Rate Normal Accelerated Depreciation
15% 34.00% 10%
Financing Debt Total IFC ADB Korean ECA Local Bank Led by SBI Tata Sons Equity 3.2 0.45 0.45 0.8 1.5 1.05
Projected Income Statement
(All figures in Rs million) Projected Income Statement Total Ann gen Capacity(Million Units or MUs) Net Ann Gen 1 FY1 2 5,76 0 4,50 4 2 FY1 3 12,0 96 9,45 9 2.26 0 21,3 78 909 7,66 2 1,15 0 2,08 1 11,3 94 2,44 8 3,67 2 3 FY1 4 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 1,15 0 6,02 8 35,1 87 2,44 8 3,67 2 4 FY1 5 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 5 FY1 6 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 6 FY1 7 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 7 FY1 8 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2
Tariff (Rs / unit)
2.26 10,1 80 433 3,64 8 1,15 0 991 4,82 3 2,44 8 0
Revenue in Millions CER Revenues
Coal Cost O & M Expenses Transportation Cost
EBITDA Depreciation -1st 2 Blocks Depreciation -last 3 blocks
46
Total Depreciation
2,44 8 2,37 5 362 6,47 9 4,46 5 0 4,46 5 2,01 7
6,12 0 5,27 4 599 16,1 96 11,5 21 0 11,5 21 5,40 1
6,12 0 29,0 67 1,45 7 16,1 96
6,12 0 27,9 17 1,60 3 16,1 96
6,12 0 27,9 17 1,60 3 15,1 34
6,12 0 27,9 17 1,60 3 14,0 71
6,12 0 27,9 17 1,60 3 13,0 08
EBIT Interest On WC Borrowing Interest on Long Term Loan
PBT Tax Paid
11,4 14 1,71 2
10,1 18 1,51 8
11,1 81 1,67 7
12,2 44 1,83 7
13,3 06 1,99 6
PAT
9,70 2
8,60 0
9,50 4
10,4 07
11,3 10
Gross Cash Accruals
15,8 22 15.0 % 1.79
14,7 20 15.0 % 1.14
15,6 24 15.0 % 1.19
16,5 27 15.0 % 1.24
17,4 30 15.0 % 1.31
Effective Tax Rate (%) DSCR Average DSCR 1.3 5
0.0% 0.37
0.0% 0.33
Projected Cash Flow Statement
Projected Cash FlowStatement Inflows: Gross Cash Accruals Deferred Tax Liability Increase in WC borrowings Total Inflows 830 Outflows: Increase in WC Loan repayment 0 0 0 2,84 7 0 2,84 7 0 1,86 6 3,53 5 1,86 6 FY1 2 2,01 7 FY1 3 5,40 1 FY1 4 FY1 5 FY1 6 FY1 7 FY1 8
15,8 22 3,88 1 6,75 8 26,4 61 6,75 8
14,7 20 3,44 0 1,15 0 19,3 10 1,15 0 8,36 7
15,6 24 3,80 1 0 19,4 25
16,5 27 4,16 3 0 20,6 90
17,4 30 4,52 4 0 21,9 55
0 8,36 7
0 8,36 7
0 8,36 7
47
Total cash outflows Net Cash Flow during the year Opening Cash Balance Closing Cash Balance
2,84 7 2,01 7 0 2,01 7
1,86 6 5,40 1 2,01 7 7,41 8
6,75 8 19,7 02 7,41 8 12,2 84
9,51 7 9,79 3 12,2 84 22,0 77
8,36 7 11,0 58 22,0 77 33,1 35
8,36 7 12,3 23 33,1 35 45,4 58
8,36 7 13,5 87 45,4 58 59,0 45
48
Working Capital Calculations Receivables (2 months) O & M expenses Total WC requirement
1,69 7 1,15 0 2,84 7 2,84 7 362 2,84 7
3,56 3 1,15 0 4,71 3 4,71 3 599 1,86 6
10,32 1 1,150 11,47 1 11,47 1 1,457 6,758
10,32 1 2,300 12,62 1 12,62 1 1,603 1,150
10,32 1 2,300 12,62 1 12,62 1 1,603 0
10,32 1 2,300 12,62 1 12,62 1 1,603 0
10,32 1 2,300 12,62 1 12,62 1 1,603 0
WC borrowings Interest on WC Increase in WC borrowings
Tax Calculations 4,46 5 15% 1 0 0 11,5 21 15% 2 0 0
PBT Tax Rate Applicable (%) Year Tax To be Paid Tax paid MAT Credit Left MAT Credit Availed Effective Tax Rate (%) Accelarated Depreciation
11,41 4 15% 3 1,712 1,712
10,11 8 15% 4 1,518 1,518
11,18 1 15% 5 1,677 1,677
12,24 4 15% 6 1,837 1,837
13,30 6 15% 7 1,996 1,996
0.00 %
0.00 %
15.00 %
15.00 %
15.00 %
15.00 %
15.00 %
Depreciation for 1st Block Accumulated Depreciation for 1st block Depreciation for 2nd Block Accumulated Depreciation for 2nd block Total Depreciation Income Tax Calculation
6,80 0 6,80 0 10,2 00 10,2 00 17,0 00
6,12 0 12,9 20 9,18 0 19,3 80 15,3 00
5,508 18,42 8 8,262 27,64 2 13,77 0
4,957 23,38 5 7,436 35,07 8 12,39 3
4,461 27,84 7 6,692 41,77 0 11,15 4
4,015 31,86 2 6,023 47,79 3 10,03 8
3,614 35,47 6 5,421 53,21 4 9,034
PBT as per Books
4,46 5
11,5 21
11,41 4
10,11 8
11,18 1
12,24 4
13,30 6
49
Add Depreciation as per Books Less Depreciation for Tax Purposes Taxable Profit Carry Forward Losses
2,44 8 17,0 00 19,0 17
6,12 0 15,3 00 20,7 01
6,120 13,77 0 3,764
6,120 12,39 3 3,845
6,120 11,15 4 6,147
6,120 10,03 8 8,325
6,120 9,034 10,39 2
Losses Carried Forward Carry Forward Losses Used to setoff Profit for Taxation Tax Rate Applicable (%) Year Tax To be Paid Tax paid MAT Credit Left MAT Credit Availed Effective Tax Rate (%) Deferred Tax Liability
0
1901 7 0
3971 8 3764 0 15% 3 0 0
3595 4 3845 0 15% 4 0 0
3211 0 6147 0 15% 5 0 0
2596 3 8325 0 15% 6 0 0
1763 8 1039 2 0 15% 7 0 0
0 15% 1 0 0
0 15% 2 0 0
Profit Before Tax Tax on Book Profit Tax actually payable with 80 IA benefit Deferred Tax Deferred Tax Liability
4,46 5 0 0 0 0
11,5 21 0 0 0 0
11,41 4 3,881 0 3,881 3,881
10,11 8 3,440 0 3,440 7,321
11,18 1 3,801 0 3,801 11,12 2
12,24 4 4,163 0 4,163 15,28 5
13,30 6 4,524 0 4,524 19,80 9
LOAN REPAYMENT SCHEDULE (All figures in Rs million) Year Loan O/S Loan Repayment to ADB and others Loan Repayment to SBI Total Repayment Loan Cl. Bal. Interest FY1 2 1 51,0 00 0 0 0 51,0 00 6,47 9 FY13 2 127,5 00 0 0 0 127,5 00 16,19 6 FY14 3 127,5 00 0 0 0 127,5 00 16,19 6 FY15 4 127,5 00 3,387 4,980 8,367 119,1 33 16,19 6 FY16 5 119,1 33 3,387 4,980 8,367 110,7 66 15,13 4 FY17 6 110,7 66 3,387 4,980 8,367 102,3 98 14,07 1 FY18 7 102,3 98 3,387 4,980 8,367 94,03 1 13,00 8 FY19 8 94,03 1 3,387 4,980 8,367 85,66 4 11,94 5
50
Projected Balance Sheet ASSETS Gross Block Less: Depreciation (Cum) Net Block Net Current Assets Cash balance Total Assets
FY1 2 68,0 00 2,44 8 65,5 52 2,84 7 2,01 7 66,3 82
FY13
FY14
FY15
FY16
FY17
FY18
FY19
170,0 00 8,568 161,4 32 4,713 7,418 158,7 27
170,0 00 14,68 8 155,3 12 11,47 1 12,28 4 179,0 67
170,0 00 20,80 8 149,1 92 12,62 1 22,07 7 183,8 90
170,0 00 26,92 8 143,0 72 12,62 1 33,13 5 188,8 28
170,0 00 33,04 8 136,9 52 12,62 1 45,45 8 195,0 31
170,0 00 39,16 8 130,8 32 12,62 1 59,04 5 202,4 98
170,0 00 45,28 8 124,7 12 12,62 1 73,13 0 210,4 64
LIABILITIES Equity Share Capital P&L Reserve Total Equity Long-term Loan WC borrowing Deferred Tax Liability
17,0 00 4,46 5 12,5 35 51,0 00 2,84 7 0
42,50 0 15,98 6 26,51 4 127,5 00 4,713 0 1587 27
42,50 0 6,284 36,21 6 127,5 00 11,47 1 3,881 1790 67
42,50 0 2,316 44,81 6 119,1 33 12,62 1 7,321 1838 90
42,50 0 11,81 9 54,31 9 110,7 66 12,62 1 11,12 2 1888 28
42,50 0 22,22 6 64,72 6 102,3 98 12,62 1 15,28 5 1950 31
42,50 0 33,53 7 76,03 7 94,03 1 12,62 1 19,80 9 2024 98
42,50 0 45,75 1 88,25 1 85,66 4 12,62 1 23,92 8 2104 64
Total Liabilities
663 82
Free Cash Flow and IRR Results
(All figures in Rs million) Projected Income Statement Free Cash Flow to firm EBITDA Tax Paid Changes in Working Capital CAPEX 0 FY1 1 1 FY1 2 4,82 3 0 2,84 7 17,0 00 2 FY13 3 FY1 4 35,1 87 1,71 2 6,75 8 0 4 FY1 5 34,0 37 1,51 8 1,15 0 0 5 FY1 6 34,0 37 1,67 7 0 0 6 FY1 7 34,0 37 1,83 7 0 0 7 FY1 8 34,0 37 1,99 6 0 0 8 FY1 9 34,0 37 2,15 5 0 0
FY09
FY1 0
0 0 0 17,00 0
0 0 0 17,0 00
0 0 0 17,0 00
11,39 4 0 1,866 102,0 00
51
Interest Payment *Tax Rate Terminal Value (if any) FCFF
0 0 17,0 00 18.14 % 70,35 9
0 0 17,0 00
0 0 17,0 00
0 0 9,33 0
0 0 88,74 0
2,64 8 0 42,8 82
2,67 0 0 36,3 40
2,51 1 0 34,8 71
2,35 1 0 34,5 52
2,19 2 0 34,2 33
2,03 2 0 33,9 14
Project IRR NPV-FCFF (Rs Million)
PAT Depreciation Capex Change in WC Net Borrowing FCFE
0 0 17,00 0 0 12,75 0 4,250 22.53 % 11,09 7
0 0 17,0 00 0 12,7 50 4,25 0
0 0 17,0 00 0 12,7 50 4,25 0
4,46 5 2,44 8 17,0 00 2,84 7 12,7 50 9,11 4
11,52 1 6,120 102,0 00 1,866 76,50 0 32,76 8
9,70 2 6,12 0 0 6,75 8 0 9,06 4
8,60 0 6,12 0 0 1,15 0 0 13,5 70
9,50 4 6,12 0 0 0 0 15,6 24
10,4 07 6,12 0 0 0 0 16,5 27
11,3 10 6,12 0 0 0 0 17,4 30
12,2 14 6,12 0 0 0 0 18,3 34
Equity IRR NPV-FCFE (Rs cr)
COE COD Post Tax COD WACC
18% 13% 8% 10.8 %
Deb t 75%
Equi ty 25%
Common size Income Statements
Projected Common Income Statement
FY12
FY13
FY14
FY15
FY16
Total Revenues Revenue in Millions CER Revenues O & M Expenses
10613 95.92% 4.08% 10.84%
22287 95.92% 4.08% 5.16%
64561 95.92% 4.08% 1.78%
64561 95.92% 4.08% 3.56%
64561 95.92% 4.08% 3.56%
52
Transportation Cost EBITDA Total Depreciation Interest On WC Borrowing Interest on Long Term Loan PBT Tax Paid PAT
9.34% 45.45% 23.07% 3.41% 61.05% -42.07% 0.00% -42.07%
9.34% 51.12% 27.46% 2.69% 72.67% -51.70% 0.00% -51.70%
9.34% 54.50% 9.48% 2.26% 25.09% 17.68% 2.65% 15.03%
9.34% 52.72% 9.48% 2.48% 25.09% 15.67% 2.35% 13.32%
9.34% 52.72% 9.48% 2.48% 23.44% 17.32% 2.60% 14.72%
References
Report and Recommendation of the President to the Board of Directors: RFQ Bid Awarding Order: Central Electricity Regulatory Commission, New Delhihttp://www.hdfcsec.com/CMT/Upload/ArticleAttachments/Tata Power - Nifty %20Series.pdf ADB: Report and Recommendation of the President to the Board of Directors
53
http://0101.netclime.net/1_5/352/258/338/NMR TTP.pdfhttp://powermin.nic.in/whats_new/pdf/development_of_project.pdfhttp://www.google.co.in/search?hl=en&rlz=1T4GUEA_enhttp://www.google.co.in/search?hl=en&rlz=1R2GUEA_en-
Project Finance (Multiple Issues)
54
doc_169659536.doc
It describes on financing project.It takes the case of TATA Mundra power project.
TATA MUNDRA POWER PROJECT
Index
1
Topic Page No. Introduction Sponsor Analysis Tata Group Tata Power Project Details Environmental and Social Concerns Assessment Power Plant Operations & Implementations Agreements Power off take agreements Indian Economy-Outlook Power Sector –Overview Electricity Act 2003 UMP CDM Kyoto Protocol CERC Risks Conclusion Financials References 3 4 4 4 8 11 12 15 20 20 30 31 34 35 36 38 42 43 51
INTRODUCTION
2
The Mundra Ultra Mega Power Project is developed by Coastal Gujarat Power Limited (CGPL) in response to the plan of the Government of India to increase the electricity production capacity of the country by 100,000 megawatts by the year 2012. To achieve economies of scale, the Government prefers large-scale projects that can meet the requirements of a number of states. The Project, awarded to CGPL on a build, own, and operate basis, is a supercritical coal-fired power plant with a total capacity of 4,000 MW. Various packages are currently at the bidding stage, and the Project is scheduled for full commercial operation in June 2012. The Project is located in a coastal area of Mundra Taluka, in Kutch District of Gujarat State. The project area covers 1,254 hectares of vacant land near the villages of Tunda and Wandh, including 202 ha of right of way outside the project boundary, and is about 2 km from the first-phase development area of the Mundra Special Economic Zone (MSEZ), where a 660 MW power plant project, the Adani Power Project, is being implemented by Adani Power Limited. The project area is about 1.5 kms from the sea, with a portion of the MSEZ intervening between the sea and the project area. For logistics and accessibility, the Project relies on (i) Mundra Port (about 25 km from the project site); (ii) state highway SH-6 (about 6 km) connecting Mundra and Mandvi; (iii) national highway extension NH 8A (about 15 km), connecting Gandhidham and Anjar with Mandvi; (iv) Adipur railway station (85 km); and (v) Bhuj airport (75 km). An access road will be constructed to provide direct access to the project site from state highway SH-6, bypassing the two villages. As many as 13 bidders submitted their bids at RFQ stage. Of these, 2 were rejected at RFQ stage itself. Of the remaining 11, 6 submitted the financial bids. The bids were as follows:
Tata Power Company Limited quoted the lowest levelised tariff for 25 year period and was awarded the project. Subsequent to completion of other formalities, TPC paid PFC 27.94 crores to acquire 100% shares of CGPL.
SPONSOR ANALYSIS
3
TATA Group:
Tata Group is a multinational conglomerate based in Mumbai, India. Tata Group is the largest private corporate group in India in terms of market capitalization and revenues, and has been recognized as one of the most respected companies in the world. It has interests in steel, automobiles, information technology, communication, power, tea and hospitality. The Tata Group has operations in more than 85 countries across six continents and its companies export products and services to 80 nations. The Tata Group comprises 114 companies and subsidiaries in seven business sectors, 27 of which are publicly listed. 65.8% of the ownership of Tata Group is held in charitable trusts. Companies which form a major part of the group include Tata Steel, Corus Steel, Tata Motors, Tata Consultancy Services, Tata Technologies, Tata Tea, Titan Industries, Tata Power, Tata Communications, Tata Teleservices, Tata Auto Comp Systems Limited and the Taj Hotels. Tata group acquired Corus for $12 billion in 2007 which is the largest overseas acquisition by an Indian firm till date.
Tata Power:
Tata Power Company Limited is a Tata Group Company and it is India’s largest private sector power company. The installed capacity of the company currently stood at 2971MW with thermal capacity at 2329MW, hydro at 447MW and wind at 195MW. TPCL has presence in all the segments of power sector such as generation, transmission, distribution and power trading. The company caters to the customers of Mumbai for more than ninety years. Apart from Mumbai and Delhi, the company has generation capacities in Jojobera, Jharkhand and Karnataka. TPCL has carried out several overseas projects and successfully completed erection, testing and commissioning of major power projects in Saudi Arabia, Bangladesh, Kuwait, Algeria, Myanmar and Thailand. The company has also undertaken projects pertaining to power plant / operations management and plant operations training. The company has a Strategic Electronic Division (SED) that has been pursuing development and production activities for the Indian defense sector. SED successfully developed the Multi Barrel Rocket Launcher, ‘Pinaka’, proven in the field through extended user trials which led to its induction into the Indian Army. The Division has developed specialized equipment for Air Defense and Naval Combat systems.
4
The company has seven subsidiaries. They are: 1. Costal Gujarat Power Limited 2. Trust Energy Resource Ltd. 3. Maithon Power Ltd. 4. Industrial Energy Ltd. 5. North Delhi Power Ltd. 6. Powerlinks Transmission Ltd. 7. Tata Power Trading Co. Ltd. In June 2007, TPC acquired a 30% stake in the KPC and Arutmin mines of Bumi Resources and is thus focusing on backward integration and fuel security.
Recent Developments: a) Fund Raising Plans TPCL has launched the $250-million FCCB issue, which includes a greenshoe option to raise another $50 million. The bonds will mature in five years and will have a yield-to maturity of 3.5 per cent on a semiannual basis. The money raised through this option will be used to fund the power projects. The company requires a debt of about Rs 236,000mn by March 2012 to complete its ongoing expansion plans. The company has already tied up for debts and other loans from various financial institutions for about Rs.181, 000 mn. TPCL has plans are to raise Rs 28,000mn through internal accruals and the rest through dilution of equity of subsidiaries, disinvestment of various holdings or assets and dilution at parent level through various vehicles. b) Strengthening of Customer Base The company is planning to add 30,000 more customers by March 2010 in Mumbai License Area. TPCL has so far received and processed 3,000 to 4,000 applications for a change-over to TPC's distribution network from mainly residential consumers in Mumbai's suburbs. The company’s current load across Mumbai stood at 400MW, which peaks at 477MW during summer seasons. Currently the company supplies to around 28,000 customers in the license area. c) Tie-Up with Invensys Operation Management
5
One of the wholly owned subsidiary of the company, Costal Gujarat Power Limted-which owns Mundra UMPP, has entered into an agreement with Invensys Operations Management, a Texas based company, to optimize India's first ultra-mega 4000MW power plant located in Mundra. Invensys will provide distributed and critical control systems, emergency shutdown systems, advanced process control, plant optimization and operator training simulator technology. Coastal Gujarat Power can leverage the global expertise and engineering capabilities of Invensys, giving them the assurance of proven delivery capability and commitment to train Coastal Gujarat's operators d) Partnership with Norway Firms Norway’s one of the fastest growing international renewable energy company, has signed a partnership agreement to develop hydro power projects in India and Nepal. The partners aim to have 2000 MW under construction or in operation by 2015, and a total of 4000 MW by 2020. This is the first time that TPCL has entered into partnership with another hydropower company. Both the companies have already began pursuing potential project opportunities based on the vast reserves of renewable energy in the Himalayas. e) Coal Block Acquisition TPCL is looking for opportunities to acquire coal blocks in Australia and Mozambique. It is also looking small coal mines in Indonesia. f) Commissioning of Mundra UMPP Units The company is planning to commission two units of the upcoming Mundra UMPP by February 2012. The aggregate capacity of these two units stood at 1,600MW.Among these the first units will commission by September 2011. The project will be commissioned fully by December 2013.
Projects under implementation: Mundra UMPP This 4,000MW project is expected to commission completely by December 2013. Around 31% of the work has been completed. 6
Maithon The first unit of this 1050MW power project is expected to commission by 2010 and the second one by 2011. It is a 74:26 joint venture between TPCL and Damodar Valley Corporation. Jojobera Unit 5 The capacity of this unit is 120MW and is expected to complete by the end the current calendar year. Around 75% of the construction work has been completed. This project is owned by one the company’s subsidiary, IEL. Captive Coal Blocks Mandakini Coal Block This 7.5MTPA coal block is situated in Orissa. Coal production from this is expected to start by July 2011. The company has mining plan approval from MoC and environment clearance, forest land approval & land acquisition are under process. Tubed Coal Block This is a joint venture between the company and Hindalco. This coal block is situated in Jharkhand. Out of the total mining capacity of 5.75MTPA, TPCL is entitled to get 2.30MTPA. Coal production from this is expected to start by February 2012. Tata Power has recently acquired 30% stake in coal fields in Indonesia (which also has ownership of Indonesian ministers)
7
PROJECT DESCRIPTION
Project Facilities The project facilities to be constructed by CGPL include the power plant and support facilities within the complex. CGPL will also construct a housing complex for project staff. Associated facilities to be constructed by other entities include: (i) (ii) (iii) (iv) A dedicated jetty and facilities for unloading and handling coal at Mundra Port A merry-go-round (MGR) rail system for transporting coal from the port to the power plant Transmission lines to convey electricity from the power plant to various designated load centers An access road.
8
Facilities to be constructed by CGPL Power Plant The power plant will consist of five pulverized coal-fired, supercritical steam electricity-generating stations, each with capacity of 830 MW. In addition to coal, fuel oil will be used for start-up, for flame stabilization, and during low-load operations. The main plant is arranged within the three interconnected structures, the (i) boiler structures, (ii) turbine building, and (iii) integrated control and electrical building. Water Production System The Project will require 25,710 m3/day of freshwater, consisting of 25,280 m3/day for process-uses, including water for coal and ash handling, and 430 m3/day for domestic uses. The freshwater will be produced from seawater in a de-salination plant. For boiler feed, a demineralization plant will further treat the freshwater supplied from the desalination plant.
Cooling Water System The power plant will have a once-through cooling system using seawater. The seawater requirement will be about 15.12 million cubic meters per day (m3/day) of which about 14.99 million m3/day will be for condenser cooling and 0.1278 million m3/day will be for producing freshwater. The seawater will be pumped at the end of an inlet channel connecting to Kotdi Creek. The spent cooling water, warmed to about 7 degrees Celsius (°C) above ambient sea water temperature, will be discharged back into the sea through a discharge channel opening to Mudhwa Creek. The inlet channel will be about 80 meters (m) wide at the bottom, 130 m wide at the top, 3 m deep, and 6.5 km long. Kotdi Creek, about 3.5 km long, will be dredged and trained to enhance its hydraulic capacity. The inlet system (inlet channel and Kotdi Creek) is designed to convey up to 630,000 cubic meters per hour (m3/hr), or somewhat more than the seawater requirement of 550,000 m3/ hr, to meet peak cooling water demand as well as the volume required for freshwater production. The outlet discharge channel will have a base width of 60 m and a length of 4.9 km. It will be designed to cool water over the first 1,900 m from the power plant. The outlet channel will discharge into Mudhwa Creek, which is about 3 km long and will be dredged and trained to increase its hydraulic capacity. Site Drainage Rainwater runoff will be collected in a pond to use in spraying the coal stockyard and for landscaping.
9
Wastewater Treatment System All process wastewaters will be treated to remove oil and stored in a pond for use in suppressing coal and ash dust and for landscaping. Reject from the desalination plant will be discharged into the sea through the discharge channel of the cooling water system. A sewage treatment plant will be provided to treat sewage from the housing complex. Residential Complex The operation of the power plant and support facilities will require about 718 people consisting of 255 CGPL staff and 463 outsourced staff. A housing complex consisting of 400 units will be developed on 182 ha of land to provide accommodation for about 255 CGPL staff and a few of the outsourced staff. Access Road An access road will be constructed from state highway SH-6 to the project site to bypass Wandh and Tunda villages.
Associated Facilities to Be Constructed by Other Entities Transmission Lines The net power produced by the power plant will be fed to a 400 kilovolt (kV) switchyard. Three 400 kV double-circuit lines will be constructed to transmit electricity from the power plant’s switchyard to Limbdi (300 km), Ranchodpur (390 km), and Jetpur (330 km). The Power Grid Corporation of India Limited will be responsible for acquiring ownership rights, rights of way, easements, and continued access rights necessary for the construction, operation, maintenance, and upgrading of the new transmission facilities. Coal Shipment and Unloading Facilities The power plant will require 11–13 million metric tons per annum (MTPA) of coal will be imported from sources such as Australia, Indonesia, and South Africa. Existing facilities at Mundra Port can handle only about 4 million MTPA of coal. Therefore, Mundra Port and Special Economic Zone Limited, the port owner, will construct a new berth and install mechanized coal-unloading facilities and a mechanized coalstacking and reclaiming system specifically to meet the coal import requirements of the Project and the Adani Power Project.
10
Rail System for Coal Transport Coal will be transported from Mundra Port to the power plant by a MGR rail system with bottom-open, bottom-release wagons. The active coal stock and the reserve stockpile at the power plant site will each be approximately 500,000 metric tons, providing a total of approximately 15 days’ coal supply in addition to the storage capacity of about 500,000 metric tons at the port.
Environmental and Social Impacts Assessment
The assessment of environmental and social impacts of the Project was conducted through the following six separate but related studies: (i) A rapid environmental impact assessment conducted by TCE Consulting Engineers Limited of India from March to May 2006, (ii) A comprehensive environmental impact assessment also conducted by TCE from March 2006 to August 2007 (iii) A socioeconomic assessment report also conducted by TCE from March to August 2006, (iv) A rapid marine impact assessment conducted by the National Institute of Oceanography from January 2006 to April 2007 and supplementary information provided in October 2007 (v) A supplementary investigation of the cumulative impacts on ambient air quality of the Project and the neighboring 660 MW power plant prepared by the Tata Power Company Limited from late October to early November 2007 in consultation with Vishudda Envirotech of India. (vi) A rapid social impact assessment conducted by Saline Area Vitalization Enterprise Limited of India in October 2007. In the course of the environmental and social assessment, a public hearing was held on 19 September 2006, and further consultations were subsequently conducted in villages. The Project received environmental clearance from the Ministry of Environment and Forests (MOEF) on 25 April 2007 based on the rapid environmental impact assessment. All other clearances and permits required for various operations from the national and state authorities have also been obtained.
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Power Plant Operations & Implementations Agreements
Construction CGPL will construct the Project through various packages. A boiler package and a turbine generator package represent approximately 50% of the total project cost. The boiler package will be procured from Doosan Heavy Industries & Construction Company Limited (Doosan) of the Republic of Korea, and the turbine generator package from Toshiba Corporation (Toshiba) of Japan. Doosan Projects Limited, an Indian incorporated company wholly owned by Doosan, is expected to provide onshore supplies and services. TCE Consulting Engineers Limited (TCE) from India will assist in preparing detailed specifications and provide engineering and design support. Korea Power Engineering Company, Inc., a subsidiary of Korea Electric Power Company Limited, the largest power utility in the Republic of Korea, will review and reinforce TCE’s work. Doosan, established in 1962, has become one of the world's major engineering, procurement, and construction contractors; and is one of the few companies in the world with the capability to design and manufacture supercritical boilers. Doosan’s business structure is organized by business groups for power generation, desalination plants, nuclear power plants, casting and forging, and construction. Its power generation business group is active in fields related to fossil fuel power generation, which includes boilers, heat recovery steam generators, turbine and generator equipment, and industrial support facilities such as material handling equipment and environmental systems. Doosan has built more than 300 nuclear, thermal, combined cycle, and hydropower plants. It is currently building more than 60 power plants in the People’s Republic of China (PRC), India, Republic of Korea, United States, and others. Doosan recently provided 660 MW supercritical boilers to National Thermal Power Corporation of India, and manufactured 800 MW supercritical boilers for Younghung Thermal Power Plant in the Republic of Korea. Toshiba started its business from a telegraph equipment factory in Tokyo in 1875, and is now a leading manufacturer of heavy electrical apparatus with a worldwide sales and service network. It has four major business areas: digital products, electric devises and components, social infrastructure systems, and home 12
appliances and others. Toshiba has delivered approximately 1,700 steam turbine units, 240 hydraulic turbine units, 300 hydraulic generator units, and 32 nuclear reactor units to customers throughout the world. It provides a vast range of turbine products, from several megawatt back-pressure turbines to over 1,000 MW supercritical 8 turbines. In February 1997, Toshiba reached the rare milestone of having produced turbine products with aggregate generating capacity of more than 100 gigawatts. Project construction will be managed with particular attention to coordination among the various contractors. An advisory council, be formed by industry experts, will assist with CGPL management, with support of Korea Power Engineering Company, Inc. The entire scope will handled by three project managers: (i) common facilities and unit 1, (ii) units 2 and 3, and (iii) units 4 and 5. Each project manager will cover engineering, procurement, and construction with support from, and coordination among, TCE, TPC's engineering and planning division, and the contractors. The Project is expected to be completed unit by unit. Commissioning of the first unit is expected by March 2011 and of the remaining units at regular 4-month intervals. The Project is expected to achieve full commercial operation by July 2012.
Coal Supply Up to 11.7 million tons of coal will be required per annum. The Government designed the Project with imported coal, and CGPL will source coal through long-term fuel supply agreements with exporters of coal in Indonesia, South Africa, Mozambique, and/or Australia, taking advantage of TPC's global coal procurement network. Despite the existing large domestic coal reserve, availability of domestic coal is not able to keep pace with the growing demand for coal for thermal generation. Under this circumstance, it is more economical to use imported coal for power plants on coastal locations, especially for those far away from the domestic coal mines. The main domestic coal reserves are in the eastern region of the country, and coal transport capacity is constrained. From the environmental perspective, the Government requires beneficiation before transporting high ash content coal over long distances. Hence, the Project, being set up on a coastal location, has been designated to use imported coal. The design of boilers would be dependent on the type of coal, and once designed for imported coal it is difficult to switch to domestic coal which has high ash content and lower calorific value. In terms of the choice of imported coal, it is important to procure quality coal with higher calorific value, lower ash, and lower sulfur. Lower ash content improves the overall plant availability due to lower maintenance requirements. Also, with higher calorific value, the Project would require less quantity of coal to generate the same level of output. To 13
achieve higher environmental standards, procurement of imported coal with lower ash and sulphur contents is essential.
Coal Transport CGPL will enter into a long-term time charter arrangement with bulk carriers for coal transport utilizing TPC's global fuel procurement network and capacity. TPC plans to set up a subsidiary to own vessels, and CGPL will enter into a time charter agreement with TPC's coal shipping subsidiary and/or directly with other shipping companies. Port Services Coal will be unloaded at Mundra Port. The concessionaire for the port, Mundra Port and Special Economic Zone Limited (MPSEZL), will provide port facilities as per the port service agreement between CGPL and MPSEZL. MPSEZL will make the terminal available and operate it to enable the minimum guaranteed tonnage to be unloaded and handled at the terminal. MPSEZL will ensure storage of at least 0.6 million t in the coal stack yard if required by CGPL. It will give berthing priority to CGPL's coal transport vessels, and make all arrangements for berthing of coal transport vessels. CGPL can also use the facilities at Mundra Port for unloading plant and equipment required for project construction. Transport of the coal from Mundra Port to the project site will be through a dedicated coal transport system. MPSEZL has agreed to provide the right-of-way for the corridor for the system, road access, and the seawater intake and discharge channel for the Project. Seawater Abstraction During operations, about 15.12 million m3/day of seawater will be used for condenser cooling and freshwater production. The spent cooling water and the reject from the desalination plant will be discharged back into the sea.
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Power Off take Agreements:
Power generated by the Project will be sold to distribution licensees of the states of Gujarat (excluding Ahmedabad and Surat Electricity Company), Maharashtra (excluding distribution companies in Mumbai), Punjab, Haryana, and Rajasthan.
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The seven offtakers that have signed power purchase agreements are: Gujarat Urja Vikas Nigam Limited The Gujarat Electricity Industry (Reorganization and Regulation) Act of 2003 restructured the Gujarat Electricity Board into seven entities with functional responsibility for trading, generation, transmission, and distribution. Gujarat Urja Vikas Nigam Limited owns 100% of the shares of the other six companies; and is responsible for bulk purchase and sale of electricity, supervision, coordination, and facilitation among the six subsidiary companies. Distribution licensees in Gujarat have a positive cash flow (including subsidy), and the deficit between average revenue and average cost is declining. However, the cross-subsidies have not changed. The substantial improvement in financial performance is mainly due to near 100% collection efficiency, reduced cost of supply because of operating efficiencies, and savings in interest costs because of debt restructuring. Maharashtra State Electricity Distribution Company Limited The Maharashtra State Electricity Board has been unbundled into four companies. In FY2006, Maharashtra State Electricity Distribution Company Limited had a negative cash flow (including subsidy) despite substantial profit in FY2004 and FY2005. The cross-subsidy has been steadily declining, indicating that a higher proportion of the cost of supply is being recovered from consumers. Collection efficiency is good, with more than 100% collection efficiency in FY2005, indicating that distribution licensees are recovering current dues and a portion of past dues. Generally, financial performance has improved. Punjab State Electricity Board (PSEB) Punjab state continues to follow an integrated model whereby all three functions of generation, transmission, and distribution are handled by PSEB. PSEB has reduced ATC losses considerably and achieved almost 100% cash collection. Its cash flow (including subsidy) has improved significantly with substantial profit in FY2004 and FY2005. During the same period, PSEB achieved a surplus between average revenue (including subsidy) and average cost. Thus PSEB performance is characterized by cash profit, dependence on subsidy from the state government because of the mid-level cross-subsidy, high collection efficiency, and relatively low ATC losses. 16
Haryana Power Generation Corporation Limited The Haryana State Electricity Board was one of the first SEBs to be unbundled along functional lines into a generation company, a transmission company, and two distribution companies. Subsequently, the trading function was separated from the transmission function. The generation company, Haryana Power Generation Company Limited, has been handling the trading and bulk purchase functions in the state since June 2005. On 14 August 1998, the transmission and distribution businesses were transferred to Haryana Vidyut Prasaran Nigam Limited. The Haryana Electricity Regulatory Commission regulates transmission and distribution. Power is wheeled through the entire network by Haryana Vidyut Prasaran Nigam Limited on the payment of transmission charges approved by the Haryana Electricity Regulatory Commission. Financial performance of the distribution licensees in Haryana are characterized by (i) not very sound cash flow positions, (ii) high dependence on subsidies, (iii) low collection efficiencies, and (iv) high ATC losses. Dependence on the state government subsidy is primarily a result of Haryana having a largely agrarian economy with state-subsidized power provided to agricultural consumers. As a result, the negative gap between average revenue (without subsidy) and average cost of supply has steadily increased. Rajasthan Power Procurement Centre It includes Ajmer Vidyut Vitaran Nigam Limited, Jaipur Vidyut Vitaran Nigam Limited, and Jodhpur Vidyut Vitaran Nigam Limited. The Rajasthan Power Sector Reforms Act of 1999 was enacted with effect from 1 June 2000, and accordingly the SEB was unbundled into five functional entities: one generation company, one transmission company, and three distribution companies: Jaipur Vidyut Vitran Nigam Limited, Ajmer Vidyut Vitran Nigam Limited, and Jodhpur Vidyut Vitran Nigam Limited. These distribution companies operate and maintain the electricity system below 66 kilovolts in their respective areas. As per the mandate of the 2003 Electricity Act, power purchase agreements (PPAs) and the procurement, bulk supply, and trading of power were transferred to the three distribution companies in February 2004. Financial performance of the distribution licensees in Rajasthan is characterized by negative cash flows, high dependence on subsidies, high collection efficiencies, high ATC losses, and a constant cross-subsidy. Dependence on the state government subsidy is primarily because the state government provides subsidies to various categories of consumers—mainly domestic and agricultural. The payment by each offtaker will be supported by an unconditional, irrevocable, and revolving letter of credit; and a default escrow account. If an offtaker defaults, CGPL has the option first to sell the power to 17
the other offtakers and second to third parties. The liability of the defaulting offtaker to make capacity charge payments to CGPL will remain unaffected for up to 3 years of capacity charges (to the extent not paid by another offtaker). If the total offtake is less than the minimum guaranteed offtake of 65%, and CGPL has paid the penalty for not purchasing the minimum quantity of fuel, CGPL is entitled to receive compensation for such penalty from the offtakers that didn’t meet the guaranteed minimum offtake. The offtakers are responsible for procuring the transmission facilities beyond the Project's 400 kilovolt switchyard bus bar under the PPA. Power from the Project will be evacuated by a dedicated transmission line to connect the Project with the grid system operated by Power Grid Corporation of India Limited. Operation and Maintenance CGPL’s in-house engineers will be responsible for project operation and maintenance with support from TPC. The key personnel of the operation and maintenance team will be deputed from TPC and its affiliates, and have expertise in thermal power engineering. Other operations personnel, with strong expertise and experience, will be recruited from outside. CGPL has recently tied up with Texas-headquartered Invensys Operations Management, to optimise India's first ultra-mega 4000MW power plant located in Mundra. Invensys will provide distributed and critical control systems, emergency shutdown systems, advanced process control, plant optimization and operator training simulator technology. The scope of the project includes the provision of end-to-end solutions, from boiler management systems to turbine auxiliary controls, with interfaces for seamless systems integration with other technology vendors. CGPL can immediately leverage the global expertise and engineering capabilities of Invensys, giving them the assurance of proven delivery capability and commitment to train Coastal Gujarat's operators.
Fuel Oil Transport The total consumption of fuel oil will be about 50,000 kiloliters per annum during uncanning operations. The fuel oil will be sourced from refineries in Jamnagar and Vadodara, etc., and will be transported to the power plant by rail or road tanker. The fuel oil will be stored in three tanks, two with 10,000 cubic meter (m3) capacity and one with 5,000 m3 capacities.
Ash Transport and Storage 18
The power plant will produce about 1.8 million MTPA of ash, of which bottom ash accounts for about 20% and fly ash 80%. Bottom ash collected in the bottom ash hopper below the boiler furnaces will be conveyed by jet pump up to the ash slurry sump for further disposal in wet form. Fly ash collected at various hoppers will be conveyed pneumatically to fly ash storage silos. Air vented out from the silos will pass through suitable control devices to remove fugitive fly ash. The dry fly ash collected in the fly ash silos will be given to fly ash users, and the remaining quantity will be disposed off in wet form. The Project has allocated about 241 ha of land for ash disposal. However, most of the ash will be utilized. Closed trucks will be used to haul the ash to utilization points.
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Economic Outlook-Indian Economy
The Indian economy entered the financial year 2008-09 on a buoyant note. During the preceding three years, the country had, witnessed tremendous economic growth with Gross Domestic Product expanding at an average of 9 per cent. However, the growth momentum was moderated because of the global economic conditions. Like all other emerging economies, India too was impacted by the credit crisis. The slowdown in growth was reflected in lower industrial production, negative exports, deceleration in services activities, dented corporate margins and diminished business confidence. As per the revised estimates for the FY 2008-09, the GDP for the year grew at 6.7 per cent as against 9.1 per cent in the previous year. But there were some comforting signs too. Well-functioning financial markets, robust rural demand, lower headline inflation and robust foreign exchange reserves were all pointers to the long term strength and resilience of the Indian Economy. The timely fiscal stimulus packages announced by the Government coupled with swift monetary easing and regulatory action by the Reserve Bank of India, helped to arrest the slow down and keep the economy ticking. The global situation saw some easing, thanks to an unprecedented and coordinated policy action by authorities across major economies of the world. Recently announced figures indicate a 10.2% growth in IIP (October 2009, YoY) which reinforces the subdued but strong growth that the Indian economy will witness. However, interest rates may be tightened going into the future because of concerns over demand-led inflation.
Power Generation in India
India is the world’s 6th largest consumer of energy, with a share of 3.4% in the world. Demand for energy is growing in India due to the rising economic prosperity of the country. The major portion of energy needs in India is met through vast coal reserves. Recent developments are increasing investments in renewable sources of energy. The total power generation in the country during FY09 was 723.55 Billion Units as against the target of 774.34 BUs, about 6% below target. The installed generation capacity in the country as on 31st March, 2009 was 147,965 MW.
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India has been traditionally dependent on thermal power as a source of power generation, which constitutes about 63 per cent of the current capacity. The balance is contributed by hydroelectric power (25 per cent), nuclear (3 per cent), and renewable energy (9 per cent). The western region accounts for the largest share (31 per cent) of the installed power generation capacity in India followed by the southern region with 27 per cent and the northern region with 26 per cent. The southern region remains the dominant region in renewable energy source accounting for more than 53 per cent of the total renewable energy based installed capacity.
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Fuel Availability Thermal coal requirement of power plants is projected to be 549 Million tonnes in 2012, against which domestic production is expected to be 482 MT. The shortfall can be covered by imports, which are expected to grow steadily from 20 MTPA in FY08 to over 60 MTPA by FY12. Projects that have already been allotted coal linkages are still unable to get a firm commitment on actual supply.
The pie chart below represents the power generation mix by ownership indicating highest generation by State boards of 52% followed by Central (33%) and Private Parties (15%).
The increase in installed power generation capacity has however not kept pace with the increase in demand for power thus leading to power shortages. The per capita consumption of electricity increased from 15 kwh in 1950 to 704 kwh in FY 2007-08, which however continues to be very low in comparison to other developed and developing countries. The gap in demand and supply has led to significant shortages as can be seen from the figures of financial year 2008-09:
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Latest Developments in Power Sector • CERC's 2009-14 Regulations With an objective of making investment in generation and transmission infrastructure more attractive without compromising consumer interest, on January 19, 2009, CERC announced tariff regulation for power generation and transmission for 2009-14. The key high lights are as under: • The base rate of Return on Equity is raised from 14% (post tax) to base rate of 15.5% to be grossed up with normal tax rate as applicable to the concerned utility. There is an additional 0.5% Roe if projects are commissioned within given time-lines. • To boost the hydro power sector, CERC has insulated new hydro projects from shortfalls in generation resulting from hydrological factors for a period of 10 years after COD. If there is an energy shortfall the energy charge for the following year would be computed on the basis of actual power generated rather than designed power generation. • • • For hydro plants Normative Annual Plant Availability Factor (NAPAF) fixed. Advance against depreciation removed. Depreciation rates to be calculated annually using straight line method as per Companies Act. The salvage value of assets fixed at 10%. After initial 12 years, the remaining depreciation to be spread over the rest of useful life of the asset.
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O&M expenses recoverable on normative basis for thermal and hydro plants. For transmission systems, O&M costs would be calculated by multiplying number of bays and Kilometers of line length with the benchmarks set for the year.
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The availability targets for thermal power plants are raised from 80% to 85% to recover fixed costs. Incentives linked to plant availability factor instead of PLF for thermal plants. Normative auxiliary consumption reduced in certain unit sizes. Reduction in normative heat rate for units of 500 MW size Recovery of capacity charge, energy charge, transmission charge and incentives would be based on operational performance. The norm for secondary oil consumption reduced from 2 ml per unit to 1 ml per unit, the savings in secondary oil consumption are to be shared with the beneficiaries in the 50:50 ratios. Generation / Transmission project developer can retain 100% carbon credits in the first year following the date of commercial operation. Generation/Transmission companies can hedge foreign exchange exposure with respect to interest on foreign currency loans and repayment of loan. Recovery of the cost of hedging and foreign exchange variation to be made directly without any application to the CERC.
• Competitive bidding tariff guidelines amended Ministry of Power in January 2005 issued guidelines for tariff determination through bidding for procurement of power by distribution licensees with an objective to facilitate transparency and fairness in the procurement process, facilitate reduction of information asymmetries for various bidders and protect consumer interest by facilitating competition. The guidelines have been recently amended to encourage sale of electricity outside the ambit of long term PPAs. Key highlights of the amendment: 1. Guidelines will be applicable for 15% of the new generating capacity which may be sold outside long term PPAs to promote market development. 2. Separate Request for Proposal (RFPs) to be invited for base load and peak load and seasonal load requirements. 3. Provision for multi-part tariff for procurement under Case 2 bidding.
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4. Hydro power tariff can be determined by the SERC provided 60% of the total saleable energy is committed to a long term PPA. • Amendment to short term inter-state open access regulations With the objective of streamlining and rationalizing inter-state open access, the following provisions have been made by CERC: • In case the State Load Dispatch Centre does not give concurrence to an inter-state open access proposal in 7 working days on first occasion and 3 working days on subsequent occasion, the concurrence of the LDC shall be deemed to have been given. • • • • • The State Load Dispatch Centres will check only two parameters i.e. availability of transmission capacity and availability of metering infrastructure. Open access customer can now request for change in schedule at notice of two days instead of the presently provided period of five days. The transmission charges for short-term open access have been rationalized. Charges on short-term open access will be disbursed directly to the long term customer by RLDC instead of routing the same through Central Transmission Utility. All disputes under inter-state access regulation to be decided by CERC.
• R-APDRP Accelerated Power Development and Reforms Programme (APDRP) were launched in X Plan by Govt. of India. This programme was modified and renamed as Restructured APDRP (R-APDRP) in 2007-08. The R-APDRP is linked to actual demonstrable performance in terms of AT&C loss reduction to 15% or less by the end of XI plan. Establishment of reliable automated systems for collection of accurate baseline data and the adoption of information technology in the areas of energy accounting are necessary preconditions for sanctioning of projects for strengthening and up-gradation of sub-transmission and distribution network. It also includes adoption of IT applications for meter reading, billing and collection, energy accounting and auditing, management information systems, redressal of consumer grievances and establishment of IT-enabled consumer service centres, besides asset mapping of the distribution network. Since its launch, the R-APDRP has made rapid headway and by February 2009, had sanctioned 599 projects in various towns and cities at a cost of Rs. 19.5 billion. Andhra Pradesh, Karnataka and Rajasthan together account for over 55 per cent of the total amount sanctioned so far. AT&C losses are showing a declining trend and have come down from 38.86% in 2001-02 to 33.07% in 2006-07. 25
Rural Electrification As per Central Electricity Authority (CEA), over 82% villageshave has been electrified. The Central Govt. launched a scheme "Rajiv Gandhi Grameen Vidyutikaran Yojana" (RGGVY) in April2005 with the goal of electrifying all (around 125000) villages and hamlets and providing access to electricity to all households in next five years. Under RGGVY, 59,882 villages have been electrified and connections to 53.78 lakh BPL households have been released up to 31.3.2009. (Source: Economic Survey 2008-09) • 100 days Agenda There has been a concerted effort to ensure that development in Power sector is not derailed. For the short term, a 100 days agenda has been drawn by MoP with a capacity addition target of 5,653 MW. Also, a high level committee /group has been set up to monitor ongoing projects and ensure their timely commissioning
Transmission and Distribution Power transmission was recognized as a separate activity and opened up to private investment in the late 1990s with several structural reforms and the unbundling of State Electricity Boards. There was an increased focus on power transmission, both by planners and by private investors after the Electricity Act, 2003 was passed. The rate of growth of the transmission network (at voltages of 220 kV and above) during the past decade has been at about 6 – 7% per annum. The inter-regional transmission capacity has increased from 5,050 MW at the end of the Ninth Plan to 20,750 MW by March 2009. However, this still falls short of the target of 14% per annum growth in transmission capacity for the Eleventh Plan. The Government policy plans to increase inter-regional transmission capacity to 58,700 MW by 2015. It is expected that thereafter, inter regional transmission will not be a constraint. The distribution network has grown from 5.73 million circuit kms in 2002 to 6.61 million Circuit kms in 2008. The target is to enhance network length to at least 7.58 million Circuit Kms by 2012. Consumer base has increased from 122 million in 2002 to 152 million in 2008. Power distribution still remains a segment that needs significant reforms, as this would have a direct impact on the sector’s commercial viability and ultimately on the consumers. The sector has been plagued by high distribution losses with low cost recovery, resulting in poor financial health of utilities. With Accelerated Power Development and Reforms Programme (APDRP), many initiatives have been introduced to reduce Aggregate Technical 26
and Commercial (AT & C) losses by modernizing distribution infrastructure. Losses in the form of theft, however, can only be eliminated through strong political will.
Power Trading Organized power trading started in India after the enactment of EA 2003. EA 2003 recognized trading as a distinct licensed activity and provided for non-discriminatory open access to generators, consumers and licensees. Tata Power Trading Company Limited was the first company to be granted license by CERC in June 2004. Presently, there are 43 licensed traders, of which the active players are TPTCL, PTC India Limited, NTPC Vidyut Vyapar Nigam Limited, Adani Enterprises Limited, Reliance Energy Trading Limited, Lanco Electric Utility Limited and JSW Power Trading Company Limited. In FY09, 32,200 MUs of energy was traded in the country, which constitutes only 4.45% of the total power generated. Power trading fulfills an important need of both consumers and generators to buy and sell power as and when needed at the prevailing market rates. Given the right policy and regulatory initiatives, such as a review of the cap on trading margin, the power trading industry has a good potential to prosper and serve the needs of the consumers in India. Introduction of Power Exchanges A Power Exchange is a fully electronic platform which facilitates buying and selling of power by members in a transparent and anonymous manner at the market discovered rates. CERC issued guidelines for setting up and operation of Power Exchanges in India. Indian Energy Exchange Limited (IEX), in which the Company is a shareholder, was the first exchange to start operations on 27th June, 2008. Power Exchange India Limited (PXI), the second power exchange promoted by National Stock Exchange of India Limited and the National Commodity and Derivatives Exchange Limited, became operational on 22nd October, 2008. In FY09, 2,628 MUs were traded on IEX and 149 MUs were traded on PXI. Development of Renewable Energy Sources (RES) for generation of power RES of 13,242 MW accounting for 9% of total installed capacity is targeted to grow to over 24,300 MW contributing to 11% of fuel basket by 2012. Over the longer term, its importance would be more strategic in view of its important role in mitigating the effects of climate change. It is imperative for India to build a certain level of self-reliance in renewable technologies of the future. The Government, in its quest for long-term energy and environmental security, is seeking to enhance the share of power from renewable sources in the overall fuel basket. India has potential for 45,000 - 65,000 MW of on shore wind power.
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70% of renewable energy is contributed by wind power generation. During past one year, solar energy, which currently contributes a little over 2 MW to the grid, received a significant boost with the National Action Plan for Climate Change mandating the setting up of a National Solar Mission. The mission is targeting 20,000 MW of solar based capacity by 2020. The steps taken by Govt. for increasing generation from renewable energy resources are: • EA 2003 requires SERCs to specify a percentage for purchase of electricity from cogeneration or renewable sources termed as Renewable Purchase Obligation (RPO). SERCs in 12 States have already specified the percentage -Andhra Pradesh, Gujarat, Karnataka, Madhya Pradesh, Orissa, Rajasthan, Tamil Nadu, Kerala, Haryana, Maharashtra, Uttar Pradesh and West Bengal. • Tariff Policy provides for competitive bidding for procurement of power from such sources - bidding to be done amongst suppliers offering power from same type of renewable source. • Procurement of power at preferential tariffs to be allowed by SERC. • Special scheme by MNRE for promoting solar power and plans for Generation Based Incentives under National Solar Mission. • CERC is in the process of finalization of regulations for sale of power generated based on RES Problems faced for development of RES • Power generation from renewable increases the uncertainty in accurate availability of power which in turn affects grid reliability and operations. • The developer of renewable generation has to provide for transmission line for power evacuation from the plant to the nearest HT Sub-station unlike conventional plants where transmission utility evacuates power. • The PPA for renewable requires the developer to guarantee the supply of a certain quantity of electricity. However, it does not require the transmission utility to provide any guarantee for grid availability. • The wind generation requires back-up capacity between the forecast and actual generation posing difficulty in open access and scheduling the power. Wind energy has separate grid codes in major wind based power generating countries. A draft grid code is under development for wind power.
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Opportunities and Outlook To achieve the Eleventh Plan targets, India needs over 65.86 GW of generation capacity addition by 2012. If this is to be achieved, it would need multiple initiatives in generation, transmission and distribution. The steady rise in demand for power as a result of economic growth is expected to present the Company with a number of opportunities. Some of these opportunities are discussed below: Opportunities in Generation The inability to add adequate generation capacity has resulted in India facing increasing power shortages every year. The Government policy thus far has only focused on adding base load generation capacity. As the standard of living improves, the demand in peaking power will increase faster than the demand for base load power. At the same time, the base load power requirement itself is expected to rise. Hence, there will also be a number of opportunities for building power plants near load centers. To expedite the target growth of power generation, the Government of India has identified the development of Ultra Mega Power Projects (UMPPs) as a thrust area. The central idea of the UMPP is to set up generation capacity on a large scale and reduce the development time of the project with the Government arranging land and all key approvals for the project. So far, four such projects of 4,000 MW capacities each have been awarded and more are planned.
Opportunities in Transmission Plans to boost transmission capacity have generally fallen short of the targets set in the Eleventh Plan. There is now a move to increase the inter-regional transmission capacity by the end of the Eleventh Plan to 37,700 MW from 20,750 MW7. Greater private sector participation is expected in the future with private developers taking an integrated approach to generation and transmission for timely evacuation of electricity from their generation projects. With use of advanced technology in transmission, there is improvement in voltage levels and grid discipline. The Government targets to attract private investment of Rs. 20,000 crores in the inter-state transmission system during the current plan period. To boost private investment in the transmission sector, the Government is developing large transmission projects through tariff based competitive bidding, based on the successful model of the UMPPs and has appointed Power Finance Corporation Limited and Rural Electrification Corporation Limited to oversee their implementation. These initiatives are expected to present the Company with opportunities. 29
Opportunities in Distribution While India has the third largest transmission and distribution network in the world, large parts of the population still have to make do without electricity or with frequent power cuts and fluctuating voltage. The regulators have played a significant role in creating an enabling environment for improving levels of service through private investment. The Central Government has introduced the APDRP to provide finances to the states to modernize distribution infrastructure. The franchisee model has been introduced recently and provides room for private sector participation in distribution. Growing commercial orientation and consumer focus along with a strong policy environment are expected to act as key drivers to shape the future outlook of distribution. As and when the distribution sector is opened up for a larger role for the private sector, it will provide a large and profitable opportunity. The Company, with its experience of distribution through its subsidiary North Delhi Power Limited (NDPL) and its own network in Mumbai, is well poised to exploit these opportunities.
Electricity Act 2003:
It came into existence in order to take favourable measures of development of electricity industry. It consolidates all the processes related to electricity generation which include generation, transmission, trading and use of electricity. The act is conducive to the growth of all the parties. It protects the interest of consumers, rationalization of electricity tariff, ensuring transparent policies regarding promotion of subsidies, promotion of efficient and environmentally benign policies constitution of Central electricity authority, regulatory commissions and promoting competition therein. Salient features of the act are: Role of government, rural electrification, generation, transmission, distribution, consumer protection, trading/market development, regulatory commission/appellate tribunal, tariff principles, CEA, measures against theft of electricity, restructuring of SEB’s. Central government prepared the National Electric Policy which is aimed at a supply of reliable and quality power of specified standard in an efficient manner and at reasonable rates and protection of consumer interests. Objective of Tariff Policy is to promote competition, efficiency in operations and 30
improvement in quality of supply and ensure availability of electricity to consumers at reasonable and competitive rates.
Ultra Mega Power Projects (UMPPs)
The Indian Government had envisaged a capacity addition of about 100 GW to meet its mission of ‘power to all by 2012’, though the target addition, for 11 th FYP, was subsequently revised downwards to about 65 GW. The need for capacity addition was, and continues to be, so huge that it was not going to be feasible from the ongoing projects. There was a need to develop large capacity projects at the national level to meet the requirements of a number of states under the competitive bidding guidelines dispensation. This gave a thrust to development of projects through competitive bidding. Ultra Mega Power Projects are steps in that direction. The proposed nine UMPPs will go a long way in substantial reduction power shortage in India. The Government proposed use of latest super critical technologies in these large power projects to achieve economies of scale leading to cheaper power. Use of Super Critical Technology was also with a view to achieve green-house gas emissions and flexibility in unit size, the latter being subject to adoption of specified minimum supercritical parameters. Various ministries and government agencies are working in tandem in successful pursuit of UMPPs, at the earliest. These UMPPs, each having a capacity of minimum 4,000 MW, would also have the scope for future expansion. These large sizes projects were to meet the power needs of a number of states through transmission of the generated power on regional and national grids to load centres. In order to enhance investor confidence, reduce risk perception and receive a good response to competitive bidding, it was deemed necessary to provide the site, fuel linkage in captive mining blocks, water, environment and forest clearance, and to make substantial progress on land acquisition ultimately leading to possession of land, and all these activities were to be done through a Shell Company. The Shell Company, in addition, would also be responsible for tying up necessary inputs from the likely buyers of power, tying up of power off takes from these projects, with appropriate terms and conditions and Payment Security Mechanism, with procurers of different states.
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The development of Ultra Mega Power Projects (UMPPs) has long been identified as a thrust area. These projects, approximately 4000 MW each, would involve an estimated investment of about Rs. 16,000 to 20,000 crores each. These projects will meet the power needs of a number of States/ distribution companies located in these States (and in states in the vicinity), and are being developed on a Build, Own, and Operate (BOO) basis. In view of the fact that promotion of competition is one of the key objectives of the Electricity Act, 2003, and of the legal provisions regarding procurement of electricity by distribution companies, identification of the project developer for these projects is being done on the basis of tariff based competitive bidding. Guidelines for determination of tariff for procurement of power by distribution licensees have been notified in January 2005 under the provisions of the Electricity Act, 2003. Power Finance Corporation (PFC) has been identified as the nodal agency for this initiative. Integrated power project would have dedicated captive coal blocks for pithead projects. Coastal projects, on the other hand were supposed to use imported coal. This was to ensure adequate supply of coal for other domestic power producers/ industries (for which using imported coal would not be feasible due to prohibitive inland transporting costs). Besides, coastal location of UMPPs made it feasible to import coal on account of economical transportation facilities of better quality coal available from mines in Indonesia, South Africa, Australia, etc. The Bidding Process: For these projects, as per the provisions of the competitive bidding guidelines, a two stage selection process has been adopted. The first stage of bidding involves Request for Qualification (RfQ) containing qualifying criteria for selection of bidders. The RfQ documents submitted by the bidders are evaluated to identify those bidders who will be eligible to participate in the second stage of the process. The second stage of the bidding process invites Request for Proposals (RfP) from the bidders so qualified. After evaluation of the RfP documents, the successful bidder is identified on the basis of the lowest levelised tariff.
32
In addition to these sites, additional sites have been identified/ suggested by Tamil Nadu (Marakanam) and Karnataka (Ghataprabha). The Central Electricity Authority is in the process of examining the feasibility of these sites for development of UMPPs.
The SPV or Shell Company is incorporated as a 100% subsidiary of PFC. Upon completion of the entire process for selection of the project developer the SPVs are transferred to the selected bidders i.e. to the selected project developers. Role of SPVs The SPVs are responsible for carrying out various activities on behalf of the procurers. Completion of these activities prior to award of the project is considered necessary to enhance the investor’s confidence, reduce risk perception and get a good response to the competitive bidding process. Some of the main activities undertaken by the SPVs include Appointment of Consultants to undertake preparation of Project Report, preparation of Rapid Environment Impact Assessment Report etc., Appointment of Consultants for International Competitive Bidding (ICB), document preparation & evaluation, To finalise RfQ/ RfP documents in consultation with States / bidders, To carry out RfQ/ RfP process and award of project, Acquisition of land for the project, Obtaining Coal blocks for pit-head projects, Getting clearance regarding allocation of water by the State Govt. for pithead locations, Approval for use of sea water from Maritime Board/ other Govt. Agencies for coastal locations, Obtain clearance from the State Pollution Control Board, initiate forest clearance etc. as are required for the project and for the coal mines, followed by environment and forest clearances from the Central Government, Obtaining geological reports/ other related data from CMPDI for the coal blocks, and Tie up the off-take/ sale of power. Role of the Ministry of Power The Ministry of Power is playing a crucial role for the development of the UMPPs by coordinating between various concerned Ministries/Agencies of the Central Government, and with various State Governments/Agencies. The key areas requiring the Ministry of Power’s intervention include Coordination with Central Ministries/Agencies for ensuring Coal block allotment/coal linkage, Environment/forest clearances, Water linkage, Required support from State Governments and their agencies, Working out allocation of power to different States from UMPPs in consultation with the States, Facilitating PPA and proper payment security mechanism with State Governments/State Utilities, and Monitoring the progress of Shell companies with respect to predetermined timelines.
33
National Electricity Plan The Electricity Act 2003, requires CEA to lay out the National Electricity Plan once in every 5 years and revise the same from time to time in accordance with the National Electricity Policy. This plan serves as a roadmap towards optimum growth of the power sector. Under this, CEA formulates short term and prospective plans for the development of electricity systems and coordinate the activities of the various planning agencies for the optimal utilisation of resources to serve the interests of the national economy Role of States States hosting the UMPPs and the other power procuring States are also required to play a pro-active role. Some of the activities in which the concerned States play a decisive role include implementation of the Rehabilitation & Resettlement Plan, provide authorization to the PFC/SPV to carry out the bidding process on behalf of the distribution utilities, participate through its representatives in various committees set up for undertaking the competitive bidding process, facilitate signing of the Power Purchase Agreement, ensure proper payment security mechanism with the distribution utilities etc.
Financing of the project The financing of the Mundra UMPP in India created a number of precedents. The financing represents the single largest foreign debt and the largest limited recourse financing to date in India; the largest financing ever done for a power plant in India; and the largest ever financing by the IFC. It is also the single largest facility by the Korean Exim Bank and Korea Export Insurance in India, and the first private sector power project in India to be based on energy efficient supercritical technology.
CDM PROJECT:
The Clean Development Mechanism (CDM) is an arrangement under the Kyoto Protocol allowing industrialized countries with a greenhouse gas reduction commitment (called Annex 1 countries) to invest in ventures that reduce emissions in developing countries as an alternative to more expensive emission reductions in their own countries. A crucial feature of an approved CDM carbon project is that it has 34
established that the planned reductions would not occur without the additional incentive provided by emission reductions credits, a concept known as "Additionality". The CDM allows net global greenhouse gas emissions to be reduced at a much lower global cost by financing emissions reduction projects in developing countries where costs are lower than in industrialized countries. The CDM is supervised by the CDM Executive Board (CDM EB) and is under the guidance of the Conference of the Parties (COP/MOP) of the United Nations Framework Convention on Climate Change (UNFCCC) Under this mechanism Certified Emission Reduction Certificates are sold to entities in Annex 1 countries which have to achieve Emission reduction targets. India is a Party to the United Nations Framework Convention on Climate Change (UNFCCC) and the objective of the Convention is to achieve stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.
THE KYOTO PROTOCOL:
The Kyoto Protocol is a protocol to the United Nations Framework Convention on Climate Change (UNFCCC or FCCC), aimed at combating global warming. The UNFCCC is an international environmental treaty with the goal of achieving "stabilization of greenhouse gas concentrations in the atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system. The Protocol was initially adopted on 11 December 1997 in Kyoto, Japan and entered into force on 16 February 2005. As of November 2009, 187 states have signed and ratified the protocol. The most notable non-member of the Protocol is the United States, which is a signatory of UNFCCC and was responsible for 36.1% of the 1990 emission levels. Under the Protocol, 37 industrialized countries (called "Annex I countries") commit themselves to a reduction of four greenhouse gases (GHG) (carbon dioxide, methane, nitrous oxide, sulphur hexafluoride) and two groups of gases (hydrofluorocarbons and perfluorocarbons) produced by them, and all member countries give general commitments. Annex I countries agreed to reduce their collective greenhouse gas emissions by 5.2% from the 1990 level. Emission limits do not include emissions by international aviation and shipping, but are in addition to the industrial gases, chlorofluorocarbons, or CFCs, which are dealt with under the 1987 Montreal Protocol on Substances that Deplete the Ozone Layer.
35
The benchmark 1990 emission levels were accepted by the Conference of the Parties of UNFCC were the values of "global warming potential" calculated for the IPCC Second Assessment Report. These figures are used for converting the various greenhouse gas emissions into comparable CO2 equivalents when computing overall sources and sinks. The Protocol allows for several "flexible mechanisms", such as emissions trading, the clean development mechanism (CDM) and joint implementation to allow Annex I countries to meet their GHG emission limitations by purchasing GHG emission reductions credits from elsewhere, through financial exchanges, projects that reduce emissions in non-Annex I countries, from other Annex I countries, or from annex I countries with excess allowances. Each Annex I country is required to submit an annual report of inventories of all anthropogenic greenhouse gas emissions from sources and removals from sinks under UNFCCC and the Kyoto Protocol. These countries nominate a person to create and manage its greenhouse gas inventory. Power sector is the most prominent sector contributing in the pollution
Central Electricity Regulatory Commission (CERC):
The Commission intends to promote competition, efficiency and economy in bulk power markets, improve the quality of supply, promote investments and advise government on the removal of institutional barriers to bridge the demand supply gap and thus foster the interests of consumers. As entrusted by the Electricity Act, 2003 the Commission has the responsibility to discharge the following functions : Mandatory Functions:• • To regulate the tariff of generating companies owned or controlled by the Central Government To regulate the tariff of generating companies other than those owned or controlled by the Central Government specified in clause (a), if such generating companies enter into or otherwise have a composite scheme for generation and sale of electricity in more than one State; • • To regulate the inter-State transmission of electricity To determine tariff for inter-State transmission of electricity 36
•
To issue licenses to persons to function as transmission licensee and electricity trader with respect to their inter-State operations
•
To adjudicate upon disputes involving generating companies or transmission licensee in regard to matters connected with clauses (a) to (d) above and to refer any dispute for arbitration
• • •
To levy fees for the purposes of the Act To specify Grid Code having regard to Grid Standards To specify and enforce the standards with respect to quality, continuity and reliability of service by licensees
• •
To fix the trading margin in the inter-State trading of electricity, if considered, necessary To discharge such other functions as may be assigned under the Act.
Advisory Functions:• • • • Formulation of National electricity Policy and tariff policy Promotion of competition, efficiency and economy in the activities of the electricity industry Promotion of investment in electricity industry Any other matter referred to the Central Commission by the Central Government
37
Key Risks
? Operational Risk ? A Super Critical technology based power plant is yet to be operational in India. Roping in of efficient & experienced operators will be critical in managing risks of Mundra UMPP ? Timely availability proper port infrastructure at Mundra is critical and delay on that account will directly affect fuel supply for the coastal plant. ? Completion Risk ? Risks of project getting delayed and/or of Cost overruns are too critical to be overemphasized. Only experienced contractors, and sub-contractors thereof, must be entrusted with the task. ? Regulatory Risk ? Export limits of coal set by Indonesian Government, if any, might pose a potential risk to uninterrupted fuel supply to GCPL. ? MAT (Minimum Alternate Tax, controlled by Central Government) ? CER Rate Volatility Risk ? Prices of Certified Emission Reductions are prone to fluctuation, based on, inter alias, supply-demand, economic cycles, implementation of Kyoto protocol. Besides, the Rupee value of CER-based revenue will also be impacted by exchange rate of Indian Rupee. ? Financial Risk 38
? Interest Rate Risk: Loans by international agencies, both multilateral as well as bilateral lending, will be floating rate loans linked to some benchmark like USD denominated LIBOR. An increase in interest rate will also increase their interest payments on rupee denominated term loan from Indian Financial Institutions. ? Currency Risk ? Rupee depreciation: Depreciation of Rupee will impact the SPV through at least three channels. The financial performance of GCPL, with respect to payments to be made to EPC contractors, repayment of interest and principal on foreign currency loans and receipt of revenues for generation of CERs, are inextricably linked to strength of the Indian Rupee vis-à-vis other Global Currencies.
Risk Matrix
39
Risk Assessment & Risk Mitigation
? In June 2007, Tata Power acquired a 30% stake in two coal mines in Indonesia to hedge the fuel supply risk for its Mundra UMPP project ? The acquisition has turned out to be meaningful, since Tata Power has enjoyed returns from higher coal prices by earning dividends from the coal mines until the commissioning of the Mundra UMPP project
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? The political and regulatory environment pose a threat to our assumptions, but we believe that the coal contracts of work (CCOW), under which the company operates provide a partial hedge to this risk ? Mundra Port and SEZ Ltd are planning a 35MT per annum terminal by 2010 and any delay in its execution could lead to fuel supply concerns. However, the total demand for 12–13MT per annum of imported coal is likely to be required only in 2013, by which time, we believe the coal terminal will be ready
? A delay in the execution of projects, would pose increased capital cost risk, owing to accumulated interest during construction, which would affect earnings. ? The company has already awarded contracts for its projects under execution and, hence, we believe delays in equipment supply would be highly unlikely. ? Since Tata Power placed orders with Toshiba and Doosan immediately after the project was awarded, we believe timely supply is likely and cost overruns can be avoided despite the significant volatility in commodity prices over the past year, as the main equipment supplier would have been able to hedge by forward buying for this project ? To hedge against varying shipping costs, the company is planning to acquire ships for coal transportation through a wholly owned subsidiary based in Singapore (this move could help it obtain tax incentives that are to shipping companies). In addition, shipping prices have fallen in the recent past, providing Tata Power the opportunity to charter ships for the long term at reasonable rates. We assume Tata Power’s average transportation cost to be INR750 per tonne for the project life led by both the acquisition and chartering of ships. ? Largest ever power plant in India with significant implementation risks including delays and cost overruns ? Key technology supplied by reputable contractors at fixed price; adequate contingencies and sponsor support for cost overruns and delays ? Fuel supply risks from imported coal could expose Project to volatility in coal pricing ? Long term coal supply contract at reasonable prices; Coastal Gujarat Power Limited plans to further diversify coal sources
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? Delays in completing the requisite transmission lines and port infrastructure ? Transmission & port infrastructure developed by reputable companies with good track record ? Off-take risks from poor creditworthiness of the state-owned utilities ? Project’s tariff is highly competitive; ensures that state utilities are incentivized to pay; power sector reforms progressing in most Indian states ? Refinancing risks after 10 years of operations because of insufficiently long tenors from local banks ? IFC and other foreign lenders providing long-term loans with 20 year tenor which will help mobilize other commercial lenders when needed ? CER price volatility in the international markets subjects the project to the risks of fluctuating gains arising out of sale of CER’s ? This risk mitigation mechanism is not freely available in the market and thus it cannot be effectively mitigated
Conclusion
The Project is a green-field project initiated in response to the Government’s energy policy. Its large capacity and use of super-critical technology, and coal as its primary fuel, make it the most cost-effective alternative for generating electricity to meet the demand backlog and support further economic growth in the state and the country. The power plant and its support facilities will be constructed on a marginal land 42
that is not ecologically or culturally sensitive. The power plant will adopt supercritical steam technology, which is about 10% more efficient than a conventional, subcritical coal-fired power plant. The Project will have no major ecological impacts, as it will adopt the best practicable mitigation measures and technologies to minimize emissions and impacts on the environment. The Project will require the contractors to adopt best environmental management practices during construction to minimize environmental disturbances such as emissions from heavy construction equipment and trucks, noise, and dust. Residual impacts will not reach the two nearby villages. Contractors will provide appropriate training to their workers in environmental, safety, and health aspects of construction, and will provide necessary protective measures to workers to minimize safety risks. The Project will adopt the best process technology and designs as well as effective pollution control equipment to minimize emissions during operations. Emissions will meet national standards as well as World Bank emission guidelines for new power plants. Impacts on ambient air quality have been found to be insignificant.
After thorough evaluation, based on risk assessment, financial viability and other associated benefits/ concerns, we recommend the project to financers.
Financials
Key Assumptions
Capacity Commisioned(MW) Completion year Fiscal Year Completion Days Operational 43
Phase
1 2 3 4 5 Project Size (MW)
800 800 800 800 800 4000
Sep-11 Jan-12 May-12 Sep-12 Jan-13
Mar-12 Mar-12 Mar-13 Mar-13 Mar-13
210 90 330 210 90
Operating Assumptions Fuel Cost Rs / ton Coal Consumption rate Kg/kWh Coal cost Rs/unit Transportation & handling costs of coal / gas O&M Expenditures (3rd Year post COD) Annual Dollar Rate 2250 0.36 0.81 0.22
50 46
Plant Load Factor (PLF) Auxialary Consumption Tariff (Rs / Kwh) Annual Tariff Escalation in percentage Useful Life (years)
85.00% 8.00% 2.26 0.00% 25
44
Grid Emission Factor (GEF) Co2 savings in 10 years in Million Tonnes CER Rate (Euro / CER) Exchange Rate (Rs / Euro) CER Rate (Rs / CER) Working Capital Assumptions Receivables (months) O&M Expenses (months)
Savings that will be made by using this critical technology in terms of CO2 or CER 28.30 12 66 792
2 1
D/T Financial Assumptions Debt Equity Total Project Cost (Rs Million)
0.75 Total Requirement 127500 42500 170000 FY09 FY10 FY11 FY12 1275 1275 0 0 4250 4250 1700 1700 0 0 FY13 76500 25500 102000
12750 12750 4250 4250 1700 1700 0 0
Debt Structure Korean Bank, ADB,IFC (in Billion Dollars) SBI(In $ Billion) Interest On Debt Repayment Period for SBI (yrs) Repayment Period for Foreign Dev. Bank (yrs) Moratorium period (Years) Cost of Equity
Interest rates 67734.3 75 59765.6 25 12.7% 12 20 3 18% 12.0% 13.5%
Depreciation (% p.a.) Estimated Salvage Value Tax Rate
3.60% 10%
45
MAT Rate Normal Accelerated Depreciation
15% 34.00% 10%
Financing Debt Total IFC ADB Korean ECA Local Bank Led by SBI Tata Sons Equity 3.2 0.45 0.45 0.8 1.5 1.05
Projected Income Statement
(All figures in Rs million) Projected Income Statement Total Ann gen Capacity(Million Units or MUs) Net Ann Gen 1 FY1 2 5,76 0 4,50 4 2 FY1 3 12,0 96 9,45 9 2.26 0 21,3 78 909 7,66 2 1,15 0 2,08 1 11,3 94 2,44 8 3,67 2 3 FY1 4 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 1,15 0 6,02 8 35,1 87 2,44 8 3,67 2 4 FY1 5 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 5 FY1 6 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 6 FY1 7 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2 7 FY1 8 35,0 40 27,4 01 2.26 0 61,9 27 2,63 4 22,1 95 2,30 0 6,02 8 34,0 37 2,44 8 3,67 2
Tariff (Rs / unit)
2.26 10,1 80 433 3,64 8 1,15 0 991 4,82 3 2,44 8 0
Revenue in Millions CER Revenues
Coal Cost O & M Expenses Transportation Cost
EBITDA Depreciation -1st 2 Blocks Depreciation -last 3 blocks
46
Total Depreciation
2,44 8 2,37 5 362 6,47 9 4,46 5 0 4,46 5 2,01 7
6,12 0 5,27 4 599 16,1 96 11,5 21 0 11,5 21 5,40 1
6,12 0 29,0 67 1,45 7 16,1 96
6,12 0 27,9 17 1,60 3 16,1 96
6,12 0 27,9 17 1,60 3 15,1 34
6,12 0 27,9 17 1,60 3 14,0 71
6,12 0 27,9 17 1,60 3 13,0 08
EBIT Interest On WC Borrowing Interest on Long Term Loan
PBT Tax Paid
11,4 14 1,71 2
10,1 18 1,51 8
11,1 81 1,67 7
12,2 44 1,83 7
13,3 06 1,99 6
PAT
9,70 2
8,60 0
9,50 4
10,4 07
11,3 10
Gross Cash Accruals
15,8 22 15.0 % 1.79
14,7 20 15.0 % 1.14
15,6 24 15.0 % 1.19
16,5 27 15.0 % 1.24
17,4 30 15.0 % 1.31
Effective Tax Rate (%) DSCR Average DSCR 1.3 5
0.0% 0.37
0.0% 0.33
Projected Cash Flow Statement
Projected Cash FlowStatement Inflows: Gross Cash Accruals Deferred Tax Liability Increase in WC borrowings Total Inflows 830 Outflows: Increase in WC Loan repayment 0 0 0 2,84 7 0 2,84 7 0 1,86 6 3,53 5 1,86 6 FY1 2 2,01 7 FY1 3 5,40 1 FY1 4 FY1 5 FY1 6 FY1 7 FY1 8
15,8 22 3,88 1 6,75 8 26,4 61 6,75 8
14,7 20 3,44 0 1,15 0 19,3 10 1,15 0 8,36 7
15,6 24 3,80 1 0 19,4 25
16,5 27 4,16 3 0 20,6 90
17,4 30 4,52 4 0 21,9 55
0 8,36 7
0 8,36 7
0 8,36 7
47
Total cash outflows Net Cash Flow during the year Opening Cash Balance Closing Cash Balance
2,84 7 2,01 7 0 2,01 7
1,86 6 5,40 1 2,01 7 7,41 8
6,75 8 19,7 02 7,41 8 12,2 84
9,51 7 9,79 3 12,2 84 22,0 77
8,36 7 11,0 58 22,0 77 33,1 35
8,36 7 12,3 23 33,1 35 45,4 58
8,36 7 13,5 87 45,4 58 59,0 45
48
Working Capital Calculations Receivables (2 months) O & M expenses Total WC requirement
1,69 7 1,15 0 2,84 7 2,84 7 362 2,84 7
3,56 3 1,15 0 4,71 3 4,71 3 599 1,86 6
10,32 1 1,150 11,47 1 11,47 1 1,457 6,758
10,32 1 2,300 12,62 1 12,62 1 1,603 1,150
10,32 1 2,300 12,62 1 12,62 1 1,603 0
10,32 1 2,300 12,62 1 12,62 1 1,603 0
10,32 1 2,300 12,62 1 12,62 1 1,603 0
WC borrowings Interest on WC Increase in WC borrowings
Tax Calculations 4,46 5 15% 1 0 0 11,5 21 15% 2 0 0
PBT Tax Rate Applicable (%) Year Tax To be Paid Tax paid MAT Credit Left MAT Credit Availed Effective Tax Rate (%) Accelarated Depreciation
11,41 4 15% 3 1,712 1,712
10,11 8 15% 4 1,518 1,518
11,18 1 15% 5 1,677 1,677
12,24 4 15% 6 1,837 1,837
13,30 6 15% 7 1,996 1,996
0.00 %
0.00 %
15.00 %
15.00 %
15.00 %
15.00 %
15.00 %
Depreciation for 1st Block Accumulated Depreciation for 1st block Depreciation for 2nd Block Accumulated Depreciation for 2nd block Total Depreciation Income Tax Calculation
6,80 0 6,80 0 10,2 00 10,2 00 17,0 00
6,12 0 12,9 20 9,18 0 19,3 80 15,3 00
5,508 18,42 8 8,262 27,64 2 13,77 0
4,957 23,38 5 7,436 35,07 8 12,39 3
4,461 27,84 7 6,692 41,77 0 11,15 4
4,015 31,86 2 6,023 47,79 3 10,03 8
3,614 35,47 6 5,421 53,21 4 9,034
PBT as per Books
4,46 5
11,5 21
11,41 4
10,11 8
11,18 1
12,24 4
13,30 6
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Add Depreciation as per Books Less Depreciation for Tax Purposes Taxable Profit Carry Forward Losses
2,44 8 17,0 00 19,0 17
6,12 0 15,3 00 20,7 01
6,120 13,77 0 3,764
6,120 12,39 3 3,845
6,120 11,15 4 6,147
6,120 10,03 8 8,325
6,120 9,034 10,39 2
Losses Carried Forward Carry Forward Losses Used to setoff Profit for Taxation Tax Rate Applicable (%) Year Tax To be Paid Tax paid MAT Credit Left MAT Credit Availed Effective Tax Rate (%) Deferred Tax Liability
0
1901 7 0
3971 8 3764 0 15% 3 0 0
3595 4 3845 0 15% 4 0 0
3211 0 6147 0 15% 5 0 0
2596 3 8325 0 15% 6 0 0
1763 8 1039 2 0 15% 7 0 0
0 15% 1 0 0
0 15% 2 0 0
Profit Before Tax Tax on Book Profit Tax actually payable with 80 IA benefit Deferred Tax Deferred Tax Liability
4,46 5 0 0 0 0
11,5 21 0 0 0 0
11,41 4 3,881 0 3,881 3,881
10,11 8 3,440 0 3,440 7,321
11,18 1 3,801 0 3,801 11,12 2
12,24 4 4,163 0 4,163 15,28 5
13,30 6 4,524 0 4,524 19,80 9
LOAN REPAYMENT SCHEDULE (All figures in Rs million) Year Loan O/S Loan Repayment to ADB and others Loan Repayment to SBI Total Repayment Loan Cl. Bal. Interest FY1 2 1 51,0 00 0 0 0 51,0 00 6,47 9 FY13 2 127,5 00 0 0 0 127,5 00 16,19 6 FY14 3 127,5 00 0 0 0 127,5 00 16,19 6 FY15 4 127,5 00 3,387 4,980 8,367 119,1 33 16,19 6 FY16 5 119,1 33 3,387 4,980 8,367 110,7 66 15,13 4 FY17 6 110,7 66 3,387 4,980 8,367 102,3 98 14,07 1 FY18 7 102,3 98 3,387 4,980 8,367 94,03 1 13,00 8 FY19 8 94,03 1 3,387 4,980 8,367 85,66 4 11,94 5
50
Projected Balance Sheet ASSETS Gross Block Less: Depreciation (Cum) Net Block Net Current Assets Cash balance Total Assets
FY1 2 68,0 00 2,44 8 65,5 52 2,84 7 2,01 7 66,3 82
FY13
FY14
FY15
FY16
FY17
FY18
FY19
170,0 00 8,568 161,4 32 4,713 7,418 158,7 27
170,0 00 14,68 8 155,3 12 11,47 1 12,28 4 179,0 67
170,0 00 20,80 8 149,1 92 12,62 1 22,07 7 183,8 90
170,0 00 26,92 8 143,0 72 12,62 1 33,13 5 188,8 28
170,0 00 33,04 8 136,9 52 12,62 1 45,45 8 195,0 31
170,0 00 39,16 8 130,8 32 12,62 1 59,04 5 202,4 98
170,0 00 45,28 8 124,7 12 12,62 1 73,13 0 210,4 64
LIABILITIES Equity Share Capital P&L Reserve Total Equity Long-term Loan WC borrowing Deferred Tax Liability
17,0 00 4,46 5 12,5 35 51,0 00 2,84 7 0
42,50 0 15,98 6 26,51 4 127,5 00 4,713 0 1587 27
42,50 0 6,284 36,21 6 127,5 00 11,47 1 3,881 1790 67
42,50 0 2,316 44,81 6 119,1 33 12,62 1 7,321 1838 90
42,50 0 11,81 9 54,31 9 110,7 66 12,62 1 11,12 2 1888 28
42,50 0 22,22 6 64,72 6 102,3 98 12,62 1 15,28 5 1950 31
42,50 0 33,53 7 76,03 7 94,03 1 12,62 1 19,80 9 2024 98
42,50 0 45,75 1 88,25 1 85,66 4 12,62 1 23,92 8 2104 64
Total Liabilities
663 82
Free Cash Flow and IRR Results
(All figures in Rs million) Projected Income Statement Free Cash Flow to firm EBITDA Tax Paid Changes in Working Capital CAPEX 0 FY1 1 1 FY1 2 4,82 3 0 2,84 7 17,0 00 2 FY13 3 FY1 4 35,1 87 1,71 2 6,75 8 0 4 FY1 5 34,0 37 1,51 8 1,15 0 0 5 FY1 6 34,0 37 1,67 7 0 0 6 FY1 7 34,0 37 1,83 7 0 0 7 FY1 8 34,0 37 1,99 6 0 0 8 FY1 9 34,0 37 2,15 5 0 0
FY09
FY1 0
0 0 0 17,00 0
0 0 0 17,0 00
0 0 0 17,0 00
11,39 4 0 1,866 102,0 00
51
Interest Payment *Tax Rate Terminal Value (if any) FCFF
0 0 17,0 00 18.14 % 70,35 9
0 0 17,0 00
0 0 17,0 00
0 0 9,33 0
0 0 88,74 0
2,64 8 0 42,8 82
2,67 0 0 36,3 40
2,51 1 0 34,8 71
2,35 1 0 34,5 52
2,19 2 0 34,2 33
2,03 2 0 33,9 14
Project IRR NPV-FCFF (Rs Million)
PAT Depreciation Capex Change in WC Net Borrowing FCFE
0 0 17,00 0 0 12,75 0 4,250 22.53 % 11,09 7
0 0 17,0 00 0 12,7 50 4,25 0
0 0 17,0 00 0 12,7 50 4,25 0
4,46 5 2,44 8 17,0 00 2,84 7 12,7 50 9,11 4
11,52 1 6,120 102,0 00 1,866 76,50 0 32,76 8
9,70 2 6,12 0 0 6,75 8 0 9,06 4
8,60 0 6,12 0 0 1,15 0 0 13,5 70
9,50 4 6,12 0 0 0 0 15,6 24
10,4 07 6,12 0 0 0 0 16,5 27
11,3 10 6,12 0 0 0 0 17,4 30
12,2 14 6,12 0 0 0 0 18,3 34
Equity IRR NPV-FCFE (Rs cr)
COE COD Post Tax COD WACC
18% 13% 8% 10.8 %
Deb t 75%
Equi ty 25%
Common size Income Statements
Projected Common Income Statement
FY12
FY13
FY14
FY15
FY16
Total Revenues Revenue in Millions CER Revenues O & M Expenses
10613 95.92% 4.08% 10.84%
22287 95.92% 4.08% 5.16%
64561 95.92% 4.08% 1.78%
64561 95.92% 4.08% 3.56%
64561 95.92% 4.08% 3.56%
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Transportation Cost EBITDA Total Depreciation Interest On WC Borrowing Interest on Long Term Loan PBT Tax Paid PAT
9.34% 45.45% 23.07% 3.41% 61.05% -42.07% 0.00% -42.07%
9.34% 51.12% 27.46% 2.69% 72.67% -51.70% 0.00% -51.70%
9.34% 54.50% 9.48% 2.26% 25.09% 17.68% 2.65% 15.03%
9.34% 52.72% 9.48% 2.48% 25.09% 15.67% 2.35% 13.32%
9.34% 52.72% 9.48% 2.48% 23.44% 17.32% 2.60% 14.72%
References
Report and Recommendation of the President to the Board of Directors: RFQ Bid Awarding Order: Central Electricity Regulatory Commission, New Delhihttp://www.hdfcsec.com/CMT/Upload/ArticleAttachments/Tata Power - Nifty %20Series.pdf ADB: Report and Recommendation of the President to the Board of Directors
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http://0101.netclime.net/1_5/352/258/338/NMR TTP.pdfhttp://powermin.nic.in/whats_new/pdf/development_of_project.pdfhttp://www.google.co.in/search?hl=en&rlz=1T4GUEA_enhttp://www.google.co.in/search?hl=en&rlz=1R2GUEA_en-
Project Finance (Multiple Issues)
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doc_169659536.doc